AMERICAN ELECTRIC POWER CO INC - Annual Report: 2017 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)



x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2017



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from __________ to_________



Commission File Number	Registrants; States of Incorporation; Address and Telephone Number	I.R.S. Employer Identification Nos.
1-3525	AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)	13-4922640
333-221643	AEP TEXAS INC. (A Delaware Corporation)	51-0007707
333-217143	AEP TRANSMISSION COMPANY, LLC (A Delaware Limited Liability Company)	46-1125168
1-3457	APPALACHIAN POWER COMPANY (A Virginia Corporation)	54-0124790
1-3570	INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)	35-0410455
1-6543	OHIO POWER COMPANY (An Ohio Corporation)	31-4271000
0-343	PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)	73-0410895
1-3146	SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) 1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 716-1000	72-0323455

Securities registered pursuant to Section 12(b) of the Act:



Registrant	Title of each class	Name of Each Exchange on Which Registered
American Electric Power Company, Inc.	Common Stock, $6.50 par value	New York Stock Exchange
AEP Texas Inc.	None
AEP Transmission Company, LLC	None
Appalachian Power Company	None
Indiana Michigan Power Company	None
Ohio Power Company	None
Public Service Company of Oklahoma	None
Southwestern Electric Power Company	None

Securities registered pursuant to Section 12(g) of the Act: None



Indicate by check mark if the registrant American Electric Power Company, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.	Yes x	No ¨

Indicate by check mark if the registrants AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.	Yes ¨	No x

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.	Yes ¨	No x

Indicate by check mark whether the registrants American Electric Power Company, Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.	Yes x	No ¨

Indicate by check mark whether the registrant AEP Texas Inc. (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.	Yes o	No x

Indicate by check mark whether the registrants have submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).	Yes x	No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.	x

Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨
Emerging growth company	¨



Indicate by check mark whether AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	x (Do not check if a smaller reporting company)	Smaller reporting company	¨
Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨



Indicate by check mark if the registrants are shell companies, as defined in Rule 12b-2 of the Exchange Act.	Yes ¨	No x

AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K.



	Aggregate Market Value of Voting and Non-Voting Common Equity Held by Non-Affiliates of the Registrants as of June 30, 2017 the Last Trading Date of the Registrants' Most Recently Completed Second Fiscal Quarter	Number of Shares of Common Stock Outstanding of the Registrants as of December 31, 2017
American Electric Power Company, Inc.	$34,179,628,893	492,005,598
		($6.50 par value)
AEP Texas Inc.	None	100
		($0.01 par value)
AEP Transmission Company, LLC (a)	None	NA

Appalachian Power Company	None	13,499,500
		(no par value)
Indiana Michigan Power Company	None	1,400,000
		(no par value)
Ohio Power Company	None	27,952,473
		(no par value)
Public Service Company of Oklahoma	None	9,013,000
		($15 par value)
Southwestern Electric Power Company	None	7,536,640
		($18 par value)


(a)	100% interest is held by AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of American Electric Power Company, Inc.


NA	Not applicable.

Note on Market Value of Common Equity Held by Non-Affiliates

American Electric Power Company, Inc. owns all of the common stock of AEP Texas Inc., Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company (see Item 12 herein).

Documents Incorporated By Reference



Description		Part of Form 10-K into which Document is Incorporated

Portions of Annual Reports of the following companies for the fiscal year ended December 31, 2017:		Part II
American Electric Power Company, Inc.
AEP Texas Inc.
AEP Transmission Company, LLC
Appalachian Power Company
Indiana Michigan Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company

Portions of Proxy Statement of American Electric Power Company, Inc. for 2018 Annual Meeting of Shareholders.		Part III

This combined Form 10-K is separately filed by American Electric Power Company, Inc., AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Except for American Electric Power Company, Inc., each registrant makes no representation as to information relating to the other registrants.

You can access financial and other information at AEP’s website, including AEP’s Principles of Business Conduct (which also serves as a code of ethics applicable to Item 10 of this Form 10-K), certain committee charters and Principles of Corporate Governance. The address is www.AEP.com. AEP makes available, free of charge on its website, copies of its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC.

TABLE OF CONTENTS



Item Number		Page Number
	Glossary of Terms	i
	Forward-Looking Information	iii

PART I
1	Business
	General	1
	Business Segments	15
	Vertically Integrated Utilities	16
	Transmission and Distribution Utilities	24
	AEP Transmission Holdco	26
	Generation & Marketing	29
	Executive Officers of AEP	32
1A	Risk Factors	33
1B	Unresolved Staff Comments	45
2	Properties	45
	Generation Facilities	45
	Transmission and Distribution Facilities	50
	Title to Property	50
	System Transmission Lines and Facility Siting	51
	Construction Program	51
	Potential Uninsured Losses	51
3	Legal Proceedings	51
4	Mine Safety Disclosure	51

PART II
5	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	52
6	Selected Financial Data	52
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	52
7A	Quantitative and Qualitative Disclosures about Market Risk	53
8	Financial Statements and Supplementary Data	53
9	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	53
9A	Controls and Procedures	53
9B	Other Information	54

	PART III
10	Directors, Executive Officers and Corporate Governance	54
11	Executive Compensation	55
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	55
13	Certain Relationships and Related Transactions and Director Independence	56
14	Principal Accounting Fees and Services	56

PART IV
15	Exhibits and Financial Statement Schedules	57
	Financial Statements	57
	Signatures	59
	Index of Financial Statement Schedules	S-1
	Reports of Independent Registered Public Accounting Firm	S-2
	Exhibit Index	E-1

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.



Term		Meaning

AEGCo		AEP Generating Company, an AEP electric utility subsidiary.
AEP		American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority owned consolidated subsidiaries and consolidated affiliates.
AEP Energy		AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.
AEP System		American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP Texas		AEP Texas Inc., an AEP electric utility subsidiary.
AEPEP		AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in the deregulated Ohio and Texas market.
AEPSC		American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo		AEP Transmission Company, LLC, and its consolidated State Transcos, a subsidiary of AEP Transmission Holdco.
AEPTCo Parent		AEP Transmission Company, LLC, the holding company of the State Transcos within the AEPTCo consolidation.
AEPTHCo		AEP Transmission Holding Company, LLC, a subsidiary of AEP, an intermediate holding company that owns transmission operations joint ventures and AEPTCo.
AEP Utilities		AEP Utilities, Inc., a former subsidiary of AEP and holding company for TCC, TNC and CSW Energy, Inc. Effective December 31, 2016, TCC and TNC were merged into AEP Utilities, Inc. Subsequently following this merger, the assets and liabilities of CSW Energy, Inc. were transferred to an affiliated company and AEP Utilities, Inc. was renamed AEP Texas Inc.
AFUDC		Allowance for Funds Used During Construction.
AGR		AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.
APCo		Appalachian Power Company, an AEP electric utility subsidiary.
CAA		Clean Air Act.
Clean Power Plan		Guidelines regulating CO₂ emissions from existing sources published by the Federal EPA in October 2015; its implementation was stayed by the U.S. Supreme Court in February 2016.
CO₂		Carbon dioxide and other greenhouse gases.
Cook Plant		Donald C. Cook Nuclear Plant, a two-unit, 2,278 MW nuclear plant owned by I&M.
CSPCo		Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
EPACT		The Energy Policy Act of 2005.
ERCOT		Electric Reliability Council of Texas regional transmission organization.
ETT		Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Federal EPA		United States Environmental Protection Agency.
FERC		Federal Energy Regulatory Commission.
I&M		Indiana Michigan Power Company, an AEP electric utility subsidiary.
IURC		Indiana Utility Regulatory Commission.
KGPCo		Kingsport Power Company, an AEP electric utility subsidiary.
KPCo		Kentucky Power Company, an AEP electric utility subsidiary.
kV		Kilovolt.
MISO		Midwest Independent Transmission System Operator.



Term		Meaning

MMBtu		Million British Thermal Units.
MW		Megawatt.
MWh		Megawatthour.
Nonutility Money Pool		Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NO_x		Nitrogen oxide.
NRC		Nuclear Regulatory Commission.
OATT		Open Access Transmission Tariff.
OCC		Corporation Commission of the State of Oklahoma.
OPCo		Ohio Power Company, an AEP electric utility subsidiary.
OVEC		Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
Parent		American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PJM		Pennsylvania – New Jersey – Maryland regional transmission organization.
PPA		Purchase Power and Sale Agreement.
PSO		Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO		Public Utilities Commission of Ohio.
PUCT		Public Utility Commission of Texas.
Registrant Subsidiaries		AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants		SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
REP		Texas Retail Electric Provider.
Rockport Plant		A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
ROE		Return on Common Equity.
RTO		Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine		Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC		U.S. Securities and Exchange Commission.
SO₂		Sulfur dioxide.
SPP		Southwest Power Pool regional transmission organization.
State Transcos		AEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, each of which is geographically aligned with AEP existing utility operating companies.
SWEPCo		Southwestern Electric Power Company, an AEP electric utility subsidiary.
TA		Transmission Agreement, effective November 2010, among APCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
TCA		Transmission Coordination Agreement dated January 1, 1997, by and among, PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two public utility subsidiaries.
TCC		Formerly AEP Texas Central Company; now a division of AEP Texas.
TNC		Formerly AEP Texas North Company; now a division of AEP Texas.
Utility Money Pool		Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
Virginia SCC		Virginia State Corporation Commission.
WPCo		Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC		Public Service Commission of West Virginia.

FORWARD-LOOKING INFORMATION

This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations,” but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook. These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected. Forward-looking statements in this document are presented as of the date of this document. Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:



Ÿ	Economic growth or contraction within and changes in market demand and demographic patterns in AEP service territories.
Ÿ	Inflationary or deflationary interest rate trends.
Ÿ	Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
Ÿ	The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
Ÿ	Electric load and customer growth.
Ÿ	Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.
Ÿ	The cost of fuel and its transportation, the creditworthiness and performance of fuel suppliers and transporters and the cost of storing and disposing of used fuel, including coal ash and spent nuclear fuel.
Ÿ	Availability of necessary generation capacity, the performance of generation plants and the availability of fuel, including processed nuclear fuel, parts and service from reliable vendors.
Ÿ	The ability to recover fuel and other energy costs through regulated or competitive electric rates.
Ÿ	The ability to build transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs.
Ÿ	New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets.
Ÿ	Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
Ÿ	Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service, environmental compliance and excess accumulated deferred income taxes.
Ÿ	Resolution of litigation.
Ÿ	The ability to constrain operation and maintenance costs.
Ÿ	Prices and demand for power generated and sold at wholesale.
Ÿ	Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
Ÿ	The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
Ÿ	Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.
Ÿ	Changes in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP.
Ÿ	Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
Ÿ	Actions of rating agencies, including changes in the ratings of debt.
Ÿ	The impact of volatility in the capital markets on the value of the investments held by the pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.
Ÿ	Accounting pronouncements periodically issued by accounting standard-setting bodies.

iii



Ÿ	Impact of federal tax reform on customer rates.
Ÿ	Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made. The Registrants expressly disclaim any obligation to update any forward-looking information. For a more detailed discussion of these factors, see “Risk Factors” in Part I of this report.

Investors should note that the Registrants announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, the Registrants may use the Investors section of AEP’s website (www.aep.com) to communicate with investors about the Registrants. It is possible that the financial and other information posted there could be deemed to be material information. The information on AEP’s website is not part of this report.

PART I

ITEM 1. BUSINESS

GENERAL

Overview and Description of Major Subsidiaries

AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company that owns, directly or indirectly, all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries.

The service areas of AEP’s public utility subsidiaries cover portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. Transmission networks are interconnected with extensive distribution facilities in the territories served. The public utility subsidiaries of AEP have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Restructuring laws in Michigan, Ohio and the ERCOT area of Texas have caused AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers. In Ohio, AEP’s regulated utility operates its distribution and transmission assets.

The member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The companies of the AEP System also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC.

As of December 31, 2017, the subsidiaries of AEP had a total of 17,666 employees. Because it is a holding company rather than an operating company, AEP has no employees. The material subsidiaries of AEP are:

AEP Texas

Organized in Delaware in 1925, AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,030,000 retail customers through REPs in west, central and southern Texas. As of December 31, 2017, AEP Texas had 1,540 employees. Among the principal industries served by AEP Texas are chemical and petroleum refining, chemicals and allied products, oil and natural gas extraction, food processing, metal refining, plastics and machinery equipment, agriculture and the manufacturing or processing of cotton seed products, oil products, precision and consumer metal products, meat products and gypsum products. The territory served by AEP Texas also includes several military installations and correctional facilities. AEP Texas is a member of ERCOT. AEP Texas is part of AEP’s Transmission and Distribution Utilities segment.

AEPTCo

Organized in Delaware in 2006, AEPTCo is a holding company for the State Transcos. The State Transcos develop and own new transmission assets that are physically connected to the AEP System. Individual State Transcos (a) have obtained the approvals necessary to operate in Indiana, Kentucky, Michigan, Ohio, Oklahoma and West Virginia, subject to any applicable siting requirements, (b) are authorized to submit projects for commission approval in Virginia and (c) have been granted consent to enter into a joint license agreement that will support investment in Tennessee. The application for regulatory approval to operate in Louisiana is under consideration, while the application for regulatory approval to operate in Arkansas was denied. Neither AEPTCo nor its subsidiaries have any employees. Instead, AEPSC and certain AEP utility subsidiaries provide the services required by these entities. AEPTCo is part of the AEP Transmission Holdco segment.

APCo

Organized in Virginia in 1926, APCo is engaged in the generation, transmission and distribution of electric power to approximately 958,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. APCo owns 6,660 MWs of generating capacity. APCo uses its generation to serve its retail and other customers. As of December 31, 2017, APCo had 1,817 employees. Among the principal industries served by APCo are paper, rubber, coal mining, textile mill products and stone, clay and glass products. APCo is a member of PJM. APCo is part of AEP’s Vertically Integrated Utilities segment.

I&M

Organized in Indiana in 1907, I&M is engaged in the generation, transmission and distribution of electric power to approximately 594,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants. I&M owns or leases 3,624 MWs of generating capacity, which it uses to serve its retail and other customers. As of December 31, 2017, I&M had 2,423 employees. Among the principal industries served are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and chemicals and allied products, rubber products and transportation equipment. I&M is a member of PJM. I&M is part of AEP’s Vertically Integrated Utilities segment.

KPCo

Organized in Kentucky in 1919, KPCo is engaged in the generation, transmission and distribution of electric power to approximately 167,000 retail customers in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. KPCo owns 1,060 MWs of generating capacity. KPCo uses its generation to serve its retail and other customers. As of December 31, 2017, KPCo had 549 employees. Among the principal industries served are petroleum refining, coal mining and chemical production. KPCo is a member of PJM. KPCo is part of AEP’s Vertically Integrated Utilities segment.

KGPCo

Organized in Virginia in 1917, KGPCo provides electric service to approximately 48,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. KGPCo does not own any generating facilities and is a member of PJM. It purchases electric power from APCo for distribution to its customers. As of December 31, 2017, KGPCo had 52 employees. KGPCo is part of AEP’s Vertically Integrated Utilities segment.

OPCo

Organized in Ohio in 1907 and re-incorporated in 1924, OPCo is engaged in the transmission and distribution of electric power to approximately 1,477,000 retail customers in Ohio. OPCo purchases energy and capacity at auction to serve generation service customers who have not switched to a competitive generation supplier. As of December 31, 2017, OPCo had 1,654 employees. Among the principal industries served by OPCo are primary metals, chemicals and allied products, health services, electronic machinery, petroleum refining, and rubber and plastic products. OPCo is a member of PJM. OPCo is part of AEP’s Transmission and Distribution Utilities segment.

PSO

Organized in Oklahoma in 1913, PSO is engaged in the generation, transmission and distribution of electric power to approximately 551,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. PSO owns 3,934 MWs of generating capacity, which it uses to serve its retail and other customers. As of December 31, 2017, PSO had 1,141 employees. Among the principal industries served by PSO are paper manufacturing, natural gas and oil extraction, transportation, oil refining, health care and aerospace. PSO is a member of SPP. PSO is part of AEP’s Vertically Integrated Utilities segment.

SWEPCo

Organized in Delaware in 1912, SWEPCo is engaged in the generation, transmission and distribution of electric power to approximately 535,000 retail customers in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. SWEPCo owns 5,250 MWs of generating capacity, which it uses to serve its retail and other customers. As of December 31, 2017, SWEPCo had 1,479 employees. Among the principal industries served by SWEPCo are natural gas and oil production, petroleum refining, manufacturing of pulp and paper, chemicals, food processing and metal refining. The territory served by SWEPCo also includes several military installations, colleges and universities. SWEPCo also owns and operates a lignite coal mining operation. SWEPCo is a member of SPP. SWEPCo is part of AEP’s Vertically Integrated Utilities segment.

WPCo

Organized in West Virginia in 1883 and reincorporated in 1911, WPCo provides electric service to approximately 42,000 retail customers in northern West Virginia. WPCo owns 780 MWs of generating capacity which it uses to serve its retail and other customers. WPCo is a member of PJM. As of December 31, 2017, WPCo had 56 employees. WPCo is part of AEP’s Vertically Integrated Utilities segment.

Service Company Subsidiary

AEP also owns a service company subsidiary, AEPSC. AEPSC provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to AEP subsidiaries. The executive officers of AEP and certain of its public utility subsidiaries are employees of AEPSC. As of December 31, 2017, AEPSC had 6,105 employees.

Public Utility Subsidiaries by Jurisdiction

The following table illustrates certain regulatory information with respect to the states in which the public utility subsidiaries of AEP operate:



Jurisdiction	Percentage of AEP System Retail Revenues (a)	AEP Utility Subsidiaries Operating in that Jurisdiction	Authorized Return on Equity (b)
Ohio	23%	OPCo	10.20%

Texas	15%	AEP Texas	9.96%
		SWEPCo	9.60%

West Virginia	13%	APCo	9.75%
		WPCo	9.75%

Virginia	12%	APCo	9.70%

Oklahoma	11%	PSO	9.30%	(c)

Indiana	11%	I&M	10.20%

Louisiana	5%	SWEPCo	9.80%

Kentucky	5%	KPCo	9.70%

Arkansas	2%	SWEPCo	10.25%

Michigan	2%	I&M	10.20%

Tennessee	1%	KGPCo	9.85%


(a)	Represents the percentage of public utility subsidiaries revenue from sales to retail customers to total public utility subsidiaries revenue for the year ended December 31, 2017.


(b)	Identifies the predominant authorized return on equity and may not include other, less significant, permitted recovery. Actual return on equity varies from authorized return on equity.


(c)	Final order received in January 2018 that approved an authorized ROE of 9.30% effective March 2018.

CLASSES OF SERVICE

The principal classes of service from which the public utility subsidiaries of AEP derive revenues and the amount of such revenues during the years ended December 31, 2017, 2016 and 2015 are as follows:



	Years Ended December 31,
Description	2017			2016			2015
	(in millions)
Vertically Integrated Utilities Segment
Retail Revenues
Residential Sales	$	3,399.8		$	3,423.1		$	3,295.4
Commercial Sales	2,148.6			2,102.2			2,057.7
Industrial Sales	2,156.9			2,050.6			2,096.9
PJM Net Charges	(1.1		)	(0.4		)	(0.7		)
Other Retail Sales	181.4			172.9			177.4
Total Retail Revenues	7,885.6			7,748.4			7,626.7
Wholesale Revenues
Off-System Sales	907.4			921.5			1,051.2
Transmission	202.2			198.2			192.2
Total Wholesale Revenues	1,109.6			1,119.7			1,243.4
Other Electric Revenues	106.1			114.5			110.4
Provision for Rate Refund	(46.4		)	(10.0		)	61.5
Other Operating Revenues	40.2			39.9			27.9
Sales to Affiliates	96.9			79.4			102.3
Total Revenues Vertically Integrated Utilities Segment	$	9,192.0		$	9,091.9		$	9,172.2

Transmission and Distribution Utilities Segment
Retail Revenues
Residential Sales	$	2,085.3		$	2,217.9		$	2,213.1
Commercial Sales	1,225.3			1,210.0			1,170.0
Industrial Sales	473.0			498.2			512.5
Other Retail Sales	39.8			38.9			37.7
Total Retail Revenues	3,823.4			3,965.0			3,933.3
Wholesale Revenues
Off-System Sales	100.5			131.0			106.1
Transmission	359.6			327.0			286.0
Total Wholesale Revenues	460.1			458.0			392.1
Other Electric Revenues	48.4			55.6			52.7
Provision for Rate Refund	(11.4		)	(159.3		)	—
Other Operating Revenues	8.4			8.9			13.9
Sales to Affiliates	90.4			94.2			164.6
Total Revenues Transmission and Distribution Utilities Segment	$	4,419.3		$	4,422.4		$	4,556.6

AEP Transmission Holdco Segment
Transmission Revenues	$	204.3		$	150.6		$	100.3
Other Operating Revenues	0.8			0.1			0.3
Sales to Affiliates	588.3			366.9			228.6
Provision for Rate Refund	(26.7		)	(4.8		)	—
Total Revenues AEP Transmission Holdco Segment	$	766.7		$	512.8		$	329.2

Generation & Marketing Segment
Generation Revenues
Affiliated	$	—		$	0.1		$	484.9
Nonaffiliated	534.6			1,534.0			1,544.5
Trading, Marketing and Retail Revenues
Affiliated	103.7			127.2			61.1
Nonaffiliated	1,218.6			1,306.7			1,299.8
Wind Generation Revenues
Nonaffiliated	18.2			18.0			22.4
Total Revenues Generation & Marketing Segment	$	1,875.1		$	2,986.0		$	3,412.7

AEP Texas



	Years Ended December 31,
Description	2017			2016		2015
	(in millions)
Retail Revenues
Residential Sales	$	573.9		$	551.2	$	553.1
Commercial Sales	449.3			421.2		447.2
Industrial Sales	107.0			102.9		106.5
Other Retail Sales	26.6			24.8		24.3
Total Retail Revenues	1,156.8			1,100.1		1,131.1
Wholesale Revenues
Transmission	293.8			258.0		222.8
Other Electric Revenues	20.8			25.1		20.2
Provision for Rate Refund	(1.1		)	—		—
Total Electric Transmission and Distribution Revenues	1,470.3			1,383.2		1,374.1
Sales to Affiliates	65.7			75.7		78.5
Other Revenues	2.4			2.5		5.4
Total Revenues	$	1,538.4		$	1,461.4	$	1,458.0

AEPTCo



	Years Ended December 31,
Description	2017			2016			2015
	(in millions)
Transmission Revenues	$	167.9		$	114.3		$	84.3
Other Operating Revenues	0.8			0.1			0.3
Sales to Affiliates	580.5			367.5			225.6
Provision for Rate Refund	(26.0		)	(3.9		)	—
Total Revenues	$	723.2		$	478.0		$	310.2

APCo



	Years Ended December 31,
Description	2017			2016			2015
	(in millions)
Retail Revenues
Residential Sales	$	1,242.8		$	1,314.8		$	1,228.3
Commercial Sales	586.0			603.0			584.6
Industrial Sales	639.0			628.9			657.1
PJM Net Charges	(0.4		)	(0.6		)	(0.2		)
Other Retail Sales	78.0			80.5			79.4
Total Retail Revenues	2,545.4			2,626.6			2,549.2
Wholesale Revenues
Off-System Sales	126.8			137.8			136.0
Transmission	57.1			45.9			53.5
Total Wholesale Revenues	183.9			183.7			189.5
Other Electric Revenues	33.4			40.5			41.7
Provision for Rate Refund	(13.7		)	(3.4		)	25.2
Total Electric Generation, Transmission and Distribution Revenues	2,749.0			2,847.4			2,805.6
Sales to Affiliates	172.0			142.1			147.8
Other Revenues	13.2			11.7			10.1
Total Revenues	$	2,934.2		$	3,001.2		$	2,963.5

I&M



	Years Ended December 31,
Description	2017			2016			2015
	(in millions)
Retail Revenues
Residential Sales	$	620.9		$	620.4		$	591.0
Commercial Sales	442.7			440.1			416.7
Industrial Sales	518.1			510.0			482.4
PJM Net Charges	(1.0		)	0.1			0.2
Other Retail Sales	7.1			7.1			7.0
Total Retail Revenues	1,587.8			1,577.7			1,497.3
Wholesale Revenues
Off-System Sales	431.2			446.6			534.7
Transmission	17.2			23.9			25.2
Total Wholesale Revenues	448.4			470.5			559.9
Other Electric Revenues	13.5			15.2			16.1
Provision for Rate Refund	(7.2		)	(1.1		)	—
Total Electric Generation, Transmission and Distribution Revenues	2,042.5			2,062.3			2,073.3
Sales to Affiliates	64.4			88.3			106.2
Other Revenues	14.3			17.0			6.7
Total Revenues	$	2,121.2		$	2,167.6		$	2,186.2

OPCo



	Years Ended December 31,
Description	2017			2016			2015
	(in millions)
Retail Revenues
Residential Sales	$	1,511.3		$	1,665.0		$	1,660.0
Commercial Sales	776.1			785.0			725.2
Industrial Sales	365.9			395.0			405.9
Other Retail Sales	13.2			14.0			13.3
Total Retail Revenues	2,666.5			2,859.0			2,804.4
Wholesale Revenues
Off-System Sales	100.5			131.0			156.1
Transmission	65.8			68.9			63.2
Total Wholesale Revenues	166.3			199.9			219.3
Other Electric Revenues	31.0			30.5			32.4
Provision for Rate Refund	(10.3		)	(159.3		)	—
Total Electricity, Transmission and Distribution Revenues	2,853.5			2,930.1			3,056.1
Sales to Affiliates	24.4			17.3			84.1
Other Revenues	6.0			6.5			8.5
Total Revenues	$	2,883.9		$	2,953.9		$	3,148.7

PSO



	Years Ended December 31,
Description	2017			2016			2015
	(in millions)
Retail Revenues
Residential Sales	$	601.4		$	538.0		$	554.5
Commercial Sales	398.5			348.6			372.4
Industrial Sales	273.4			220.6			263.1
Other Retail Sales	80.9			70.8			76.7
Total Retail Revenues	1,354.2			1,178.0			1,266.7
Wholesale Revenues
Off-System Sales	13.9			13.1			11.5
Transmission	42.3			38.3			38.6
Total Wholesale Revenues	56.2			51.4			50.1
Other Electric Revenues	8.5			14.9			14.6
Provision for Rate Refund	(1.4		)	(0.1		)	—
Total Electric Generation, Transmission and Distribution Revenues	1,417.5			1,244.2			1,331.4
Sales to Affiliates	4.3			3.1			4.6
Other Revenues	5.4			4.4			3.2
Total Revenues	$	1,427.2		$	1,251.7		$	1,339.2

SWEPCo



	Years Ended December 31,
Description	2017			2016			2015
	(in millions)
Retail Revenues
Residential Sales	$	597.0		$	587.7		$	593.5
Commercial Sales	492.5			479.0			471.5
Industrial Sales	331.4			307.1			318.8
Other Retail Sales	8.8			8.1			8.2
Total Retail Revenues	1,429.7			1,381.9			1,392.0
Wholesale Revenues
Off-System Sales	251.3			243.9			252.7
Transmission	71.7			78.4			60.2
Total Wholesale Revenues	323.0			322.3			312.9
Other Electric Revenues	20.4			20.0			21.1
Provision for Rate Refund	(21.0		)	(4.4		)	36.3
Total Electric Generation, Transmission and Distribution Revenues	1,752.1			1,719.8			1,762.3
Sales to Affiliates	25.9			24.5			16.6
Other Revenues	1.9			2.0			2.0
Total Revenues	$	1,779.9		$	1,746.3		$	1,780.9

FINANCING

General

Companies within the AEP System generally use short-term debt to finance working capital needs. Short-term debt may also be used to finance acquisitions, construction and redemption or repurchase of outstanding securities until such needs can be financed with long-term debt. In recent history, short-term funding needs have been provided for by cash on hand and AEP’s commercial paper program. Funds are made available to subsidiaries under the AEP corporate borrowing program. Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity. See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2017 Annual Reports, under the heading entitled Financial Condition for additional information concerning short-term funding and access to bank lines of credit, commercial paper and capital markets.

AEP’s revolving credit agreement (which backstops the commercial paper program) includes covenants and events of default typical for this type of facility, including a maximum debt/capital test. In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of its major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements. As of December 31, 2017, AEP was in compliance with its debt covenants. With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before termination of the agreement. A voluntary bankruptcy or insolvency of AEP or one of its significant subsidiaries would be considered an immediate termination event. See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2017 Annual Reports, under the heading entitled Financial Condition for additional information with respect to AEP’s credit agreement.

AEP’s subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as securitization financings and leasing arrangements, including the leasing of coal transportation equipment and facilities.

ENVIRONMENTAL AND OTHER MATTERS

General

AEP subsidiaries are currently subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities. The environmental issues that management believes are potentially material to the AEP System are outlined below.

Clean Water Act Requirements

Operations for AEP subsidiaries are subject to the Federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and regulates systems that withdraw surface water for use in power plants. In 2014, the Federal EPA issued a final rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. The standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement. Compliance with this standard is required within eight years of the effective date of the final rule. The standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment. Challenges to this final rule have been consolidated in the U.S. Court of Appeals for the Second Circuit, and additional changes could be made to this rule as a result of review by the court.

In November 2015, the Federal EPA issued a final rule to update the technology-based standards that govern discharges from new and existing power plants under the Clean Water Act’s National Pollutant Discharge Elimination System program. For additional information, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues.

Coal Ash Regulation

AEP’s operations produce a number of different coal combustion by-products, including fly ash, bottom ash, gypsum and other materials. Effective October 2015, the Federal EPA adopted a rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units. The final rule requires certain standards for location, groundwater monitoring and dam stability to be met at landfills and certain surface impoundments at operating facilities on a schedule to be implemented by the end of 2018. If existing disposal facilities cannot meet these standards, they will be required to close, but the time frame for closure may be extended if adequate alternative disposal options are not available. For additional information regarding the Federal EPA action taken to regulate the disposal and beneficial re-use of coal combustion residuals and the potential impact on operations, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues - Coal Combustion Residual Rule.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control mobile and stationary sources of air emissions. The major CAA programs affecting AEP’s power plants are described below. The states implement and administer many of these programs and could impose additional or more stringent requirements. AEP has made significant long-term investments in environmental controls to reduce air emissions from its power plants. Between 2000 and 2017, AEP invested approximately $8.6 billion in environmental controls, primarily related to the CAA, that have significantly reduced emissions. From 2001 and including projections through 2018, AEP expects its emissions of mercury will be lower by approximately 8,300 pounds, a reduction of approximately 87%. Since 1990 and including projections through 2018, AEP expects its emissions of SO₂and NO_x will be lower by approximately 1,460,000 tons and 560,000 tons, respectively, a reduction of approximately 94% and 89%, respectively.

The Acid Rain Program

The 1990 Amendments to the CAA include a cap-and-trade emission reduction program for SO₂ emissions from power plants. By 2000, the program established a nationwide cap on power plant SO₂ emissions of 8.9 million tons per year and required further reductions in 2010. The 1990 Amendments also contain requirements for power plants to reduce NO_x emissions through the use of available combustion controls.

The success of the SO₂ cap-and-trade program encouraged the Federal EPA and the states to use it as a model for other emission reduction programs. AEP continues to meet its obligations under the Acid Rain Program through the installation of controls, use of alternate fuels and participation in the emissions allowance markets. Subsequent programs developed by the Federal EPA have imposed more stringent SO₂ and NO_x emission reduction requirements than the Acid Rain Program on many AEP facilities. Additional controls and other actions have been taken to achieve compliance with these programs at these facilities.

National Ambient Air Quality Standards (NAAQS)

The CAA requires the Federal EPA to review the available scientific data for criteria pollutants periodically and establish a concentration level in the ambient air for those substances that is adequate to protect the public health and welfare with an extra safety margin. The Federal EPA also can list additional pollutants and develop concentration levels for them. These concentration levels are known as national ambient air quality standards (NAAQS).

Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (nonattainment areas). Each state must develop a state implementation plan (SIP) to bring nonattainment areas into compliance with the NAAQS and maintain good air quality in attainment areas. All SIPs are submitted to the Federal EPA for approval. If a state fails to develop adequate plans, the Federal EPA develops and implements a plan. As the Federal EPA reviews the NAAQS and establishes new concentration levels, the attainment status of areas can change and states may be required to develop new SIPs. In 2008, the Federal EPA issued revised NAAQS for both ozone and fine particulate matter (PM_2.5). The PM_2.5 standard was remanded by the D.C. Circuit Court of Appeals, and a new rule that lowered the annual standard was signed by the administrator in December 2012. A new ozone standard was adopted in 2015. The Federal EPA also adopted a new short-term standard for SO₂ in 2010, a lower standard for NO_x in 2010, and confirmed the existing standard for lead in 2016. The existing standard for carbon monoxide was retained in 2011. The states are in the process of developing new SIPs for the SO₂, PM_2.5 and ozone standards, which could result in more stringent emission limitations being imposed on AEP facilities.

In 2005, the Federal EPA issued the Clean Air Interstate Rule (CAIR), which required additional reductions in SO₂ and NO_x emissions from power plants and assists states developing new SIPs to meet the NAAQS. In August 2011, the Federal EPA issued a final rule to replace CAIR (the Cross State Air Pollution Rule (CSAPR)) that contains more stringent requirements to control SO₂ and NO_x emissions from fossil fuel-fired electric generating units in 27 states and the District of Columbia. Petitions for review were filed with the U.S. Court of Appeals for the District of Columbia Circuit, and CSAPR was vacated. That decision was subsequently reversed by the U.S. Supreme Court and remanded back to the U.S. Court of Appeals for further proceedings. The Federal EPA filed a motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. The court granted the Federal EPA’s motion, and remanded certain state budgets to the Federal EPA for further rulemaking while the rule remains in effect. The Federal EPA adopted more stringent NO_x budgets for 23 states during the 2017 ozone season based on the 2008 ozone NAAQS. For additional information regarding CSAPR, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues - Clean Air Act Requirements.

Hazardous Air Pollutants

As a result of the 1990 Amendments to the CAA, the Federal EPA investigated hazardous air pollutant (HAP) emissions from the electric utility sector and submitted a report to Congress, identifying mercury emissions from coal-fired power plants as warranting further study. In 2011, the Federal EPA issued a final rule setting Maximum Achievable Control Technology (MACT) standards for new and existing coal and oil-fired utility units and New Source Performance Standards (NSPS) for emissions from new and modified power plants. Petitions for review of the MACT standards were denied by the U.S. Court of Appeals for the D.C. Circuit, but in 2014 the U.S. Supreme Court determined that the Federal EPA acted unreasonably in refusing to consider costs in determining if it was appropriate and necessary to regulate hazardous air pollutant emissions from electric generating units. The Federal EPA has issued a supplemental finding, which has also been challenged in the courts, and the rule remains in effect.

Regional Haze

The CAA establishes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing impairment of visibility in these areas (Regional Haze program). In 2005, the Federal EPA issued its Clean Air Visibility Rule (CAVR), detailing how the CAA’s best available retrofit technology requirements will be applied to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.

PSO executed a settlement with the Federal EPA and the State of Oklahoma to comply with Regional Haze program requirements in Oklahoma, and the settlement is now codified in the Oklahoma SIP. PSO is in the process of implementing the requirements of the SIP. The Federal EPA has disapproved portions of the Arkansas and Texas SIPs, and finalized a Federal Implementation Plan for Arkansas in 2016 and a Plan for Texas in 2017. Challenges to both federal plans are pending in the courts. For additional information regarding CAVR and the Regional Haze program requirements, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues - Clean Air Act Requirements.

Climate Change

AEP has taken action to reduce and offset CO₂ emissions from its generating fleet and expects CO₂ emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. In February 2018, AEP announced new intermediate and long-term CO₂ emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, regulations, and grid reliability and resiliency, and reflect the company’s current business strategy. The intermediate goal is a 60% reduction from 2000 CO₂ emission levels from AEP generating facilities by 2030; the long-term goal is an 80% reduction of CO₂ emissions from AEP generating facilities from 2000 levels by 2050. AEP’s total projected CO₂ emissions in 2018 are approximately 90 million metric tons, a 46% reduction from AEP’s 2000 CO₂ emissions of approximately 167 million metric tons. The Federal EPA has taken action to regulate CO₂ emissions from new and existing fossil fueled electric generating units under the existing provisions of the CAA. The Federal EPA published the Clean Power Plan in October 2015. The Clean Power Plan is being legally challenged by numerous parties and final regulatory outcomes remain uncertain. In February 2016, the U.S. Supreme Court issued a stay on the final Clean Power Plan, including all of the deadlines for submission of initial or final state plans. The stay will remain in effect until a final decision is issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review. In 2017, the Federal EPA issued a proposal to repeal the Clean Power Plan and an advance notice of proposed rulemaking seeking information that should be considered in the development of new emission guidelines. For additional information regarding the Federal EPA action taken to regulate CO₂ emissions, including the Clean Power Plan, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues-Climate Change, CO₂ Regulation and Energy Policy.

Management expects emissions to continue to decline over time as AEP diversifies generating sources and operates fewer coal units. The projected decline in coal-fired generation is due to a number of factors, including the ongoing cost of operating older units, the relative cost of coal and natural gas as fuel sources, increasing environmental regulations requiring significant capital investments and changing commodity market fundamentals. Management’s strategy for this transformation includes diversifying AEP’s fuel portfolio and generating more electricity from natural gas, increasing energy efficiency and investing in renewable resources, where there is regulatory support.

Renewable Sources of Energy

The states AEP serves, other than Kentucky, West Virginia and Tennessee, have established mandatory or voluntary programs to increase the use of energy efficiency, alternative energy or renewable energy sources.

At the end of 2017, the AEP operating companies had long-term contracts for 2,630 MWs of wind and 10 MWs of solar power delivering renewable energy to the companies’ customers; this includes APCo’s 119.7 MW long-term wind contract in Indiana, which began deliveries in January 2018. In addition, I&M owns four solar projects that make up I&M’s 14.7 MW Clean Energy Solar Pilot Project (CESPP) that was approved by the IURC. This resulted in a total of 2,655 MWs of wind and solar in-service serving AEP’s regulated utilities. Management actively manages AEP’s compliance position and is on pace to meet the relevant requirements or benchmarks in each applicable jurisdiction.

The growth of AEP’s renewable portfolio reflects the company’s strategy to diversify its generation resources to provide clean energy options to customers. In addition to gradually reducing AEP’s reliance on coal-fueled generating units, the growth of renewables and natural gas helps AEP to maintain a diversity of generation resources.

The integrated resource plans filed with state regulatory commissions by AEP’s regulated utility subsidiaries reflect AEP’s renewable strategy to balance reliability and cost with customers’ desire for clean energy in a carbon-constrained world. AEP has committed significant capital investments to modernize the electric grid and integrate these new resources. Transmission assets of the AEP System interconnect approximately 11,900 MWs of renewable energy resources, and AEP’s transmission development initiatives are designed to facilitate the interconnection of additional renewable energy resources.

AEP Energy Supply, LLC owns 311 MWs of wind capacity in Texas and sells its energy entitlement to third parties or liquidates at market. In 2017, AEP took several major steps in executing its strategic plan to develop and market a merchant distributed resource portfolio. AEP Renewables, LLC, was formed in April 2016 to develop and/or acquire large scale renewable projects backed with long-term contracts with creditworthy counterparties. In 2017, AEP Renewables, LLC brought into service a 28 MW solar project in California and owns a 26 MW solar project in Utah and a 62 MW solar project in Nevada that were brought into service in 2016 and 2017, respectively.

AEP OnSite Partners, LLC works directly with wholesale and large retail customers to provide tailored solutions to reduce their energy costs based upon market knowledge, innovative applications of technology and deal structuring capabilities. The company targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions that create value for customers. AEP OnSite Partners, LLC pursues and develops behind the meter projects with creditworthy customers. As of December 31, 2017, AEP OnSite Partners, LLC owned projects operating in 12 states, including 63 MWs of installed solar capacity, and another 34 MWs of solar projects under construction.

Competitive Renewable Generation Facilities



Size of		Renewable		In Service or
Energy Resource	AEP Entity	Energy Resource	Location	Under Construction
311 MW	AEP Energy Supply LLC	Wind	Texas	In service
28 MW	AEP Renewables, LLC	Solar	California	In service
26 MW	AEP Renewables, LLC	Solar	Utah	In service
62 MW	AEP Renewables, LLC	Solar	Nevada	In service
63 MW	AEP OnSite Partners, LLC	Solar	Twelve states (a)	In service
34 MW	AEP OnSite Partners, LLC	Solar	Six states (b)	Under Construction


(a)	California, Colorado, Florida, Hawaii, Minnesota, New Hampshire, New Jersey, New Mexico, New York, Ohio, Texas and Vermont.


(b)	California, Colorado, Minnesota, New Mexico, New York and Ohio.

End Use Energy Efficiency

Beginning in 2008, AEP ramped up efforts to reduce energy consumption and peak demand through the introduction of additional energy efficiency and demand response programs. These programs, commonly and collectively referred to as demand side management, were implemented in jurisdictions where appropriate cost recovery was available. Since that time, AEP operating companies implemented programs that have reduced annual consumption by over 7 million MWhs and peak demand by approximately 2,280 MWs. AEP estimates that its operating companies spent approximately $1.2 billion during that period to achieve these levels.

Energy efficiency and demand reduction programs have received regulatory support in most of the states AEP serves, and appropriate cost recovery will be essential for AEP operating companies to continue and expand these consumer offerings. Appropriate recovery of program costs, lost revenues and an opportunity to earn a reasonable return ensures that energy efficiency programs are considered equally with supply side investments. As AEP continues to transition to a cleaner, more efficient energy future, energy efficiency and demand response programs will continue to play an important role in how the company serves its customers.

Corporate Governance

In response to environmental issues and in connection with its assessment of AEP’s strategic plan, the Board of Directors continually reviews the risks posed by new environmental rules and requirements that could accelerate the retirement of coal-fired generation assets. The Board of Directors is informed of any new environmental regulations and proposed regulation or legislation that would affect the company. The Board’s Committee on Directors and Corporate Governance oversees the company’s annual Corporate Accountability Report, which includes information about the company’s environmental, financial and social performance. In addition, as a result of ongoing corporate governance outreach efforts with shareholders, AEP set new carbon dioxide emission reduction goals that were published in a new report in February 2018, “American Electric Power: Strategic Vision for a Clean Energy Future.”

Other Environmental Issues and Matters

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 imposes costs for environmental remediation upon owners and previous owners of sites, as well as transporters and generators of hazardous material disposed of at such sites. See Note 6 to the financial statements entitled Commitments, Guarantees and Contingencies, included in the 2017 Annual Reports, under the heading entitled The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation for further information.

Environmental Investments

Investments related to improving AEP System plants’ environmental performance and compliance with air and water quality standards during 2015, 2016 and 2017 and the current estimate for 2018 are shown below. These investments include both environmental as well as other related spending. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental

regulations, business opportunities, market volatility, economic trends and the ability to access capital. In addition to the amounts set forth below, AEP expects to make substantial investments in future years in connection with the modification and addition at generation plants’ facilities for environmental quality controls. Such future investments are needed in order to comply with air and water quality standards that have been adopted and have deadlines for compliance after 2017 or have been proposed and may be adopted. Future investments could be significantly greater if emissions reduction requirements are accelerated or otherwise become more onerous. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System. AEP typically recovers costs of complying with environmental standards from customers through rates in regulated jurisdictions. For AEP’s merchant generation units however, there is no such recovery mechanism. Failure to recover these costs could reduce future net income and cash flows and possibly harm AEP’s financial condition. See Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading entitled Environmental Issues and Note 6 to the financial statements, entitled Commitments, Guarantees and Contingencies, included in the 2017 Annual Reports, for more information regarding environmental expenditures in general.



Historical and Projected Environmental Investments

	2015		2016		2017		2018
	Actual		Actual		Actual		Estimate (b)
	(in millions)
AEP (a)	$	599.4	$	383.7	$	135.9	$	150.9
APCo	78.4		50.0		25.6		28.1
I&M	45.6		65.0		41.9		35.3
PSO	92.3		34.8		0.6		1.0
SWEPCo	243.8		82.1		11.7		28.7


(a)	Includes expenditures of the subsidiaries shown and other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies.


(b)	Estimated amounts are exclusive of debt AFUDC.

Management continues to refine the cost estimates of complying with air and water quality standards and other impacts of the environmental proposals. The following cost estimates for periods following 2018 will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules. These cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans (SIPs) or federal implementation plans (FIPs) that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired, replaced or sold, including the type and amount of such replacement capacity and (g) other factors.

Management’s current ranges of estimates of new major environmental investments excluding unregulated assets beginning in 2018, exclusive of debt AFUDC, are set forth below:



Projected (2019 - 2025) Environmental Investment
Company	Low		High
	(in millions)
AEP	$	2,000	$	2,600
APCo	150		240
I&M	800		960
PSO	15		45
SWEPCo	140		280

BUSINESS SEGMENTS

AEP’s Reportable Segments

AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

AEP’s reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities


•	Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities


•	Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo and AEP Texas.


•	OPCo purchases energy and capacity to serve Standard Service Offer customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco


•	Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity.


•	Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.

Generation & Marketing


•	Competitive generation in ERCOT and PJM.


•	Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO.


•	Contracted renewable energy investments and management services.

The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEP River Operations, LLC (AEPRO), a commercial barge operation, in November 2015, the activities related to the AEPRO segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.

VERTICALLY INTEGRATED UTILITIES

GENERAL

AEP’s vertically integrated utility operations are engaged in the generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities on behalf of each of these subsidiaries.

ELECTRIC GENERATION

Facilities

As of December 31, 2017, AEP’s vertically integrated public utility subsidiaries owned or leased approximately 23,000 MWs of domestic generation. See Item 2 – Properties for more information regarding the generation capacity of vertically integrated public utility subsidiaries.

Fuel Supply

The following table shows the owned and leased generation sources by type (including wind purchase agreements), on an actual net generation (MWhs) basis, used by the Vertically Integrated Utilities:



	2017	2016	2015
Coal and Lignite	61%	61%	66%
Nuclear	18%	16%	16%
Natural Gas	11%	13%	11%
Renewables	10%	10%	7%

A price increase/decrease in one or more fuel sources relative to other fuels, as well as the addition of renewable resources, may result in the decreased/increased use of other fuels. AEP’s overall 2017 fossil fuel costs for the Vertically Integrated Utilities remained flat on a dollar per MMBtu basis from 2016.

Coal and Lignite

AEP’s Vertically Integrated Utilities procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations and spot agreements with various producers and coal trading firms. Coal consumption in 2017 decreased from 2016 due to additional planned outages.

Management believes that the Vertically Integrated Utilities will be able to secure and transport coal and lignite of adequate quality and in adequate quantities to operate their coal and lignite-fired units. Through subsidiaries, AEP owns, leases or controls more than 3,675 railcars, 468 barges, 11 towboats and a coal handling terminal with approximately 18 million tons of annual capacity to move and store coal for use in AEP generating facilities.

Spot market prices for coal started to strengthen in the second half of 2017. The increased spot coal prices reflect tighter supplies and increased demand for export coal. As of December 31, 2017, approximately half of the coal purchased by AEP’s subsidiaries was procured through term contracts. As those contracts expire or re-open for price adjustments, needed tonnage is replaced at current market prices as necessary. The price impact of this process is reflected in subsequent periods. The price paid for coal delivered in 2017 decreased approximately 4% from 2016.

The following table shows the amount of coal and lignite delivered to the Vertically Integrated Utilities plants during the past three years and the average delivered price of coal purchased by the Vertically Integrated Utilities:



	2017		2016		2015
Total coal delivered to the plants (millions of tons)	29.3		30.0		37.3
Average cost per ton of coal delivered	$	44.24	$	45.92	$	45.36

The coal supplies at the Vertically Integrated Utilities plants vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. As of December 31, 2017, the Vertically Integrated Utilities’ coal inventory was approximately 37 days of full load burn. While inventory targets vary by plant and are changed as necessary, the current coal inventory target for the Vertically Integrated Utilities is approximately 30 days.

Natural Gas

The Vertically Integrated Utilities consumed approximately 86 billion cubic feet of natural gas during 2017 for generating power. This represents a decrease of 17% from 2016. Total gas consumption for the Vertically Integrated Utilities was lower year over year primarily because higher natural gas prices in 2017 caused natural gas plants to be used less (and for coal plants to be used more). Several of AEP’s natural gas-fired power plants are connected to at least two pipelines which allow greater access to competitive supplies and improve delivery reliability. A portfolio of term, monthly, seasonal and daily supply and transportation agreements provide natural gas requirements for each plant, as appropriate. AEP’s natural gas supply agreements are entered into on a competitive basis and based on market prices.

The following table shows the amount of natural gas delivered to the Vertically Integrated Utilities’ plants during the past three years and the average delivered price of natural gas purchased by the Vertically Integrated Utilities.



	2017		2016		2015
Total natural gas delivered to the plants (billion of cubic feet)	86.3		103.9		89.7
Average price per MMBtu of purchased natural gas	$	3.37	$	2.77	$	2.80

Nuclear

I&M has made commitments to meet the current nuclear fuel requirements of the Cook Plant. I&M has made and will make purchases of uranium in various forms in the spot, short-term and mid-term markets. I&M also continues to finance its nuclear fuel through leasing.

For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M completed modifications to its spent nuclear fuel storage pool more than 10 years ago. I&M entered into an agreement to provide for onsite dry cask storage of spent nuclear fuel to permit normal operations to continue. I&M is scheduled to conduct further dry cask loading and storage projects on an ongoing periodic basis. I&M completed its initial loading of spent nuclear fuel into the dry casks in 2012, which consisted of 12 casks (32 spent nuclear fuel assemblies contained within each). The second loading of spent nuclear fuel into dry casks was completed in 2015, which consisted of 16 casks. The third dry cask loading campaign, which is forecasted to also load 16 casks, is expected to begin in the summer of 2018.

Nuclear Waste and Decommissioning

As the owner of the Cook Plant, I&M has a significant future financial commitment to dispose of spent nuclear fuel and decommission and decontaminate the plant safely. The cost to decommission a nuclear plant is affected by NRC regulations and the spent nuclear fuel disposal program. The most recent decommissioning cost study was completed in 2015. The estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant was $1.6 billion in 2015 non-discounted dollars, with additional ongoing estimated costs of $5 million per year for post decommissioning storage of spent nuclear fuel and an eventual estimated cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. As of December 31, 2017, the total decommissioning trust fund balance for the Cook Plant was approximately $2.2 billion. The balance of funds available to eventually decommission Cook Plant will differ based on contributions and investment returns. The ultimate cost of retiring the Cook Plant may be materially different from estimates and funding targets as a result of the:


•	Escalation of various cost elements (including, but not limited to, general inflation and the cost of energy).


•	Further development of regulatory requirements governing decommissioning.


•	Technology available at the time of decommissioning differing significantly from that assumed in studies.


•	Availability of nuclear waste disposal facilities.


•	Availability of a United States Department of Energy facility for permanent storage of spent nuclear fuel.

Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly different than current projections. AEP will seek recovery from customers through regulated rates if actual decommissioning costs exceed projections. See Note 6 to the financial statements, entitled Commitments, Guarantees and Contingencies under the heading Nuclear Contingencies, included in the 2017 Annual Reports, for information with respect to nuclear waste and decommissioning.

Low-Level Radioactive Waste

The Low-Level Waste Policy Act of 1980 mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. Michigan does not currently have a disposal site for such waste available. I&M cannot predict when such a site may be available. However, the states of Utah and Texas have licensed low level radioactive waste disposal sites which currently accept low level radioactive waste from Michigan waste generators. There is currently no set date limiting I&M’s access to either of these facilities. The Cook Plant has a facility onsite designed specifically for the storage of low level radioactive waste. In the event that low level radioactive waste disposal facility access becomes unavailable, it can be stored onsite at this facility.

Counterparty Risk Management

The Vertically Integrated Utilities segment also sells power and enters into related energy transactions with wholesale customers and other market participants. As a result, counterparties and exchanges may require cash or cash related instruments to be deposited on transactions as margin against open positions. As of December 31, 2017, counterparties posted approximately $9 million in cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP’s public utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries posted approximately $60 million with counterparties and exchanges). Since open trading contracts are valued based on market prices of various commodities, exposures change daily. See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2017 Annual Reports, under the heading entitled Quantitative and Qualitative Disclosures About Market Risk for additional information.

Certain Power Agreements

I&M

The Unit Power Agreement between AEGCo and I&M, dated March 31, 1982, provides for the sale by AEGCo to I&M of all the capacity (and the energy associated therewith) available to AEGCo at the Rockport Plant. Whether or not power is available from AEGCo, I&M is obligated to pay a demand charge for the right to receive such power (and an energy charge for any associated energy taken by I&M). The agreement will continue in effect until the last of the lease terms of Unit 2 of the Rockport Plant have expired (currently December 2022) unless extended in specified circumstances.

Pursuant to an assignment between I&M and KPCo, and a unit power agreement between AEGCo and KPCo, AEGCo sells KPCo 30% of the capacity (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo has agreed to pay to AEGCo the amounts that I&M would have paid AEGCo under the terms of the Unit Power Agreement between AEGCo and I&M for such entitlement. The KPCo unit power agreement expires in December 2022.

OVEC

AEP and several nonaffiliated utility companies jointly own OVEC. The aggregate equity participation of AEP in OVEC is 43.47%. Parent owns 39.17% and OPCo owns 4.3%. Under the Inter-Company Power Agreement (ICPA), which defines the rights of the owners and sets the power participation ratio of each, the sponsoring companies are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. The ICPA terminates in June 2040. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and to provide a return on its equity capital. AEP and the other owners have authorized environmental investments related to their ownership interests. OVEC financed capital expenditures totaling $1.3 billion in connection with flue gas desulfurization projects and the associated scrubber waste disposal landfills at its two generation plants through debt issuances, including tax-advantaged debt issuances. Both OVEC generation plants are operating with the new environmental controls in service. OPCo attempted to assign its rights and obligations under the ICPA to an affiliate as part of its transfer of its generation assets and liabilities in keeping with corporate separation required by Ohio law. OPCo failed to obtain the consent to assignment from the other owners of OVEC and therefore filed a request with the PUCO seeking authorization to maintain its ownership of OVEC. In December 2013, the PUCO approved OPCo’s request, subject to the condition that energy from the OVEC entitlements are sold into the day-ahead or real-time PJM energy markets, or on a forward basis through a bilateral arrangement. In November 2016, the PUCO approved OPCo’s request to approve a cost-based purchased power agreement (PPA) rider, effective in January 2017, that would initially be based upon OPCo’s contractual entitlement under the ICPA which is approximately 20% of OVEC’s capacity. Some parties filed a rehearing challenge to the PUCO decision, which was denied. Those parties filed an appeal before the Supreme Court of Ohio to challenge the PUCO’s decision, which remains pending. In late 2016, two nonaffiliated parties to the ICPA owned by First Energy Corp. (“FE”) announced its intention to exit its merchant business and that it may pursue restructuring or bankruptcy. FE’s aggregate power participation ratio is approximately 8% under the ICPA. Presently, FE has yet to pursue restructuring or bankruptcy. However, as a result of this announcement and other related developments, Moody’s downgraded OVEC’s rating with a negative outlook for possible downgrade, while Fitch and S&P have revised OVEC’s outlook to negative.

ELECTRIC DELIVERY

General

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2 – Properties for more information regarding the transmission and distribution lines. Most of the transmission and distribution services are sold to retail customers of AEP’s vertically integrated public utility subsidiaries in their service territories. These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC. See Item 1. Business – Vertically Integrated Utilities – Regulation – Rates. The FERC regulates and approves the rates for both wholesale transmission transactions and wholesale generation contracts. The use and the recovery of costs associated with the transmission assets of the AEP vertically integrated public utility subsidiaries are subject to the rules, principles, protocols and agreements in place with PJM and SPP, and as approved by the FERC. See Item 1. Business – Vertically Integrated Utilities – Regulation – FERC. As discussed below, some transmission services also are separately sold to non-affiliated companies.

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the exclusive right to provide electric service within a specific territory. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business. For a discussion of competition in the sale of power, see Item 1. Business – Vertically Integrated Utilities – Competition.

Transmission Agreement (TA)

APCo, I&M, KGPCo, KPCo and WPCo own and operate transmission facilities that are used to provide transmission service under the PJM OATT and are parties to the TA. OPCo, a subsidiary in AEP’s Transmission and Distribution Utilities segment, is also a party to the TA. The TA defines how the parties to the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM. The TA has been approved by the FERC.

TCA, OATT, and ERCOT Protocols

PSO, SWEPCo and AEPSC are parties to the TCA. Under the TCA, a coordinating committee is charged with the responsibility of (a) overseeing the coordinated planning of the transmission facilities of the parties to the agreement, including the performance of transmission planning studies, (b) the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and (c) compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff. Pursuant to the TCA, AEPSC has responsibility for monitoring the reliability of their transmission systems and administering the OATT on behalf of the other parties to the agreement. The TCA also provides for the allocation among the parties of revenues collected for transmission and ancillary services provided under the OATT. These allocations have been determined by the FERC-approved OATT for the SPP.

Regional Transmission Organizations

AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM, and PSO and SWEPCo are members of the SPP (both FERC-approved RTOs). RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.

REGULATION

General

AEP’s vertically integrated public utility subsidiaries’ retail rates and certain other matters are subject to traditional cost-based regulation by the state utility commissions. AEP’s vertically integrated public utility subsidiaries are also subject to regulation by the FERC under the Federal Power Act with respect to wholesale power and transmission service transactions. I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant. AEP and its vertically integrated public utility subsidiaries are also subject to the regulatory provisions of EPACT, much of which is administered by the FERC.

Rates

Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. A utility’s cost of service generally reflects its operating expenses, including operation and maintenance expense, depreciation expense and taxes. State utility commissions periodically adjust rates pursuant to a review of (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment. Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time, a state utility commission can review and change rates on its own initiative. Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers. Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.

Public utilities have traditionally financed capital investments until the new asset is placed in service. Provided the asset was found to be a prudent investment, it was then added to rate base and entitled to a return through rate recovery. Given long lead times in construction, the high costs of plant and equipment and volatile capital markets, management actively pursues strategies to accelerate rate recognition of investments and cash flow. AEP representatives continue to engage state commissioners and legislators on alternative ratemaking options to reduce regulatory lag and enhance certainty in the process. These options include pre-approvals, a return on construction work in progress, rider/trackers, formula rates and the inclusion of future test-year projections into rates.

The rates of AEP’s vertically integrated public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service). Historically, the state regulatory frameworks in the service area of the AEP vertically integrated public utility subsidiaries reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility’s rates and tariffs. Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes.

The following state-by-state analysis summarizes the regulatory environment of certain major jurisdictions in which AEP’s vertically integrated public utility subsidiaries operate. Several public utility subsidiaries operate in more than one jurisdiction. See Note 4 to the financial statements, entitled Rate Matters, included in the 2017 Annual Reports, for more information regarding pending rate matters.

Indiana

I&M provides retail electric service in Indiana at bundled rates approved by the IURC, with rates set on a cost-of-service basis. Indiana provides for timely fuel and purchased power cost recovery through a fuel cost recovery mechanism.

Oklahoma

PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC. PSO’s rates are set on a cost-of-service basis. Fuel and purchased energy costs are recovered or refunded by applying fuel adjustment and other factors to retail kilowatt-hour sales.

Virginia

APCo currently provides retail electric service in Virginia at unbundled generation and distribution rates, currently frozen, approved by the Virginia SCC. Virginia generally allows for timely recovery of fuel costs through a fuel adjustment clause. In addition to base rates and fuel cost recovery, APCo is permitted to recover a variety of costs through rate adjustment clauses including transmission services provided at OATT rates based on rates established by the FERC.

West Virginia

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. West Virginia generally allows for timely recovery of fuel costs through an expanded net energy cost which trues-up to actual expenses.

FERC

Under the Federal Power Act, the FERC regulates rates for interstate power sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. The FERC regulations require AEP’s vertically integrated public utility subsidiaries to provide open access transmission service at FERC-approved rates, and AEP has approved cost-based formula transmission rates on file at the FERC. The FERC also regulates unbundled transmission service to retail customers. In addition, the FERC regulates the sale of power for resale in interstate commerce by (a) approving contracts for wholesale sales to municipal and cooperative utilities and (b) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices. AEP’s vertically integrated public utility subsidiaries have market-based rate authority from the FERC, under which much of their wholesale marketing activity takes place. The FERC requires each public utility that owns or controls interstate transmission facilities to, directly or through an RTO, to file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system. The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. Additionally, the vertically integrated public utility subsidiaries are subject to reliability standards promulgated by the North American Electric Reliability Corporation, with the approval of the FERC.

The FERC oversees RTOs, entities created to operate, plan and control utility transmission assets. FERC Order 2000 prescribes certain characteristics and functions of acceptable RTO proposals. AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM. PSO and SWEPCo are members of SPP.

The FERC has jurisdiction over the issuances of securities of most of AEP’s public utility subsidiaries, the acquisition of securities of utilities, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system.

COMPETITION

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries generate, transmit and distribute electricity to retail customers of AEP’s vertically integrated public utility subsidiaries in their service territories. These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC, and are not subject to competition from other vertically integrated public utilities. Other than AEGCo, AEP’s vertically integrated public utility subsidiaries hold franchises or other rights that effectively grant the exclusive ability to provide electric service in various municipalities and regions in their service areas.

AEP’s vertically integrated public utility subsidiaries compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil, renewables and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize alternative sources of energy other than electric power. With respect to competing generators and self-generation, the public utility subsidiaries of AEP believe that they currently maintain a competitive position.

Changes in regulatory policies and advances in newer technologies for batteries or energy storage, fuel cells, microturbines, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production. The costs of photovoltaic solar cells in particular have continued to become increasingly competitive. The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AEP’s competitiveness.

SEASONALITY

The sale of electric power is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of AEP’s facilities and the terms of power sale contracts into which AEP enters. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish AEP’s results of operations. Conversely, unusually extreme weather conditions could increase AEP’s results of operations.

TRANSMISSION AND DISTRIBUTION UTILITIES

GENERAL

This segment consists of the transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo. OPCo is engaged in the transmission and distribution of electric power to approximately 1,477,000 retail customers in Ohio. OPCo purchases energy and capacity at auction to serve generation service customers who have not switched to a competitive generation supplier. AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,030,000 retail customers through REPs in west, central and southern Texas.

AEP’s transmission and distribution utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2 – Properties for more information regarding the transmission and distribution lines. Transmission and distribution services are sold to retail customers of AEP’s transmission and distribution utility subsidiaries in their service territories. These sales are made at rates approved by the PUCT for AEP Texas and by the PUCO and the FERC for OPCo. The FERC regulates and approves the rates for wholesale transmission transactions. As discussed below, some transmission services also are separately sold to non-affiliated companies.

AEP’s transmission and distribution utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the exclusive right to provide electric service. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business.

The use and the recovery of costs associated with the transmission assets of the AEP transmission and distribution utility subsidiaries are subject to the rules, protocols and agreements in place with PJM and ERCOT, and as approved by the FERC. In addition to providing transmission services in connection with power sales in their service areas, AEP’s transmission and distribution utility subsidiaries through RTOs also provide transmission services for non-affiliated companies.

Transmission Agreement (TA)

OPCo owns and operates transmission facilities that are used to provide transmission service under the PJM OATT; OPCo is a party to the TA with other utility subsidiary affiliates. The TA defines how the parties to the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM. The TA has been approved by the FERC.

Regional Transmission Organizations

OPCo is a member of PJM, a FERC-approved RTO. RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not. AEP Texas is a member of ERCOT.

REGULATION

OPCo provides distribution and transmission services to retail customers within its service territory at cost-based rates approved by the PUCO or by the FERC. AEP Texas provides transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules. Transmission and distribution rates are established on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. The cost of service generally reflects operating expenses, including operation and maintenance expense, depreciation expense and taxes. Utility commissions periodically adjust rates pursuant to a review of (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.

FERC

Under the Federal Power Act, the FERC regulates rates for transmission of electric power, accounting and other matters. The FERC regulations require AEP to provide open access transmission service at FERC-approved rates, and it has approved cost-based formula transmission rates on file at the FERC. The FERC also regulates unbundled transmission service to retail customers. The FERC requires each public utility that owns or controls interstate transmission facilities to, directly or through an RTO, file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system. The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system. Additionally, the transition and distribution utility subsidiaries are subject to reliability standards promulgated by the North American Electric Reliability Corporation, with the approval of the FERC.

SEASONALITY

The delivery of electric power is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months. In other areas, power demand peaks during the winter months. The pattern of this fluctuation may change due to the nature and location of AEP’s transmission and distribution facilities. In addition, AEP transmission and distribution has historically delivered less power, and consequently earned less income, when weather conditions are milder. In Texas, and to a lesser extent, in Ohio, where we have residential decoupling, unusually mild weather in the future could diminish AEP’s results of operations. Conversely, unusually extreme weather conditions could increase AEP’s results of operations.

AEP TRANSMISSION HOLDCO (AEPTHCO)

GENERAL

AEPTHCo is a holding company for (a) AEPTCo, which is the direct holding company for the State Transcos and (b) AEP’s Transmission Joint Ventures.

AEPTCo

AEPTCo wholly owns the State Transcos:


•	AEP Appalachian Transmission Company, Inc. (APTCo)


•	AEP Indiana Michigan Transmission Company, Inc. (IMTCo)


•	AEP Kentucky Transmission Company, Inc. (KTCo)


•	AEP Ohio Transmission Company, Inc. (OHTCo)


•	AEP West Virginia Transmission Company, Inc. (WVTCo)


•	AEP Oklahoma Transmission Company, Inc. (OKTCo)


•	AEP Southwestern Transmission Company, Inc. (SWTCo)

The State Transcos are independent of, but respectively overlay, the following AEP electric utility operating companies: APCo, I&M, KPCo, KGPCo, OPCo, PSO, SWEPCo, and WPCo. The State Transcos develop, own, operate, and maintain their respective transmission assets. Assets of the State Transcos interconnect to transmission facilities owned by the aforementioned operating companies and unaffiliated transmission owners within the footprints of PJM and SPP. APTCo, IMTCo, KTCo, OHTCo, and WVTCo are located within PJM. OKTCo and SWTCo are located within SPP.

IMTCo, KTCo, OHTCo, OKTCo, and WVTCo have received all necessary approvals for formation and currently own and operate transmission assets in their respective jurisdictions. In December 2016, the Virginia SCC and WVPSC granted consent for APCo and APTCo to enter into a joint license agreement that will support APTCo investment in the state of Tennessee. An application for regulatory approval for SWTCo is under consideration in Louisiana.

The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. The State Transcos establish transmission rates each year through formula rate filings with the FERC. The rate filings calculate the revenue requirement needed to cover the costs of operation and debt service and to earn an allowed return on equity. These rates are then included in an OATT for SPP and PJM.

The State Transcos own, operate, maintain and invest in transmission infrastructure in order to maintain and enhance system integrity and grid reliability, grid security, safety, reduce transmission constraints and facilitate interconnections of new generating resources and new wholesale customers, as well as enhance competitive wholesale electricity markets. A key part of AEP’s business is replacing and upgrading transmission facilities, assets and components of the existing AEP System as needed to maintain reliability.

The State Transcos provide the capability to replace and upgrade existing facilities. As of December 31, 2017, the State Transcos had $5.5 billion of transmission assets in-service with plans to construct approximately $4.3 billion of additional transmission assets through 2020. Additional investment in transmission infrastructure is needed within PJM and SPP to maintain the required level of grid reliability, resiliency, security and efficiency and to address an aging transmission infrastructure. Additional transmission facilities will be needed based on changes in generating resources, such as wind or solar projects, generation additions or retirements, and additional new customer interconnections. AEP will continue its investment to enhance physical and cyber security of assets, and are also investing in improving the telecommunication network that supports the operation and control of the grid.

AEPTHCO JOINT VENTURE INITIATIVES

AEP has established joint ventures with other electric utility companies for the purpose of developing, building, and owning transmission assets that seek to improve reliability and market efficiency and provide transmission access to remote generation sources in North America (Transmission Joint Ventures).

The Transmission Joint Ventures currently include:



Joint Venture Name	Location	Projected or Actual Completion Date		Owners (Ownership %)	Total Estimated Project Costs at Completion			AEP's Investment as of December 31, 2017 (j)			Approved Return on Equity
					(in millions)
ETT	Texas	(a)		Berkshire Hathaway	$	3,260.0	(a)	$	664.3		9.6	%
	(ERCOT)			Energy (50%)
				AEP (50%)

Prairie Wind	Kansas	2014		Westar Energy (50%)	158.0			21.7			12.8	%
				Berkshire Hathaway Energy (25%)
				AEP (25%) (b)

Pioneer	Indiana	2018	(c)	Duke Energy (50%)	1,100.0		(c)	41.4			12.54	%
				AEP (50%)

RITELine IN	Indiana	2026		Exelon (12.5%)	400.0			—		(e)	11.43	%
RITELine IN				AEP (87.5%) (d)

RITELine IL	Illinois	2026		Commonwealth	1,200.0			—		(e)	11.43	%
RITELine IL				Edison (75%)
				Exelon (12.5%)
				AEP (12.5%) (d)

Transource	Missouri	2016		Great Plains Energy	310.5			162.1			11.1	%	(g)
Missouri				(13.5%)
				AEP (86.5%) (f)

Transource	West	2019		Great Plains Energy	72.0			2.7			10.5	%
West Virginia	Virginia			(13.5%) (f)
				AEP (86.5%) (f)

Transource	Maryland	2020		Great Plains Energy	26.0		(h)	1.8			10.4	%	(i)
Maryland				(13.5%) (f)
				AEP (86.5%) (f)

Transource	Pennsylvania	2020		Great Plains Energy	204.0		(h)	4.0			10.4	%	(i)
Pennsylvania				(13.5%) (f)
				AEP (86.5%) (f)


(a)	ETT is undertaking multiple projects and the completion dates will vary for those projects. ETT’s investment in completed, current and future projects in ERCOT over the next ten years is expected to be $3.3 billion. Future projects will be evaluated on a case-by-case basis.


(b)	AEP owns 25% of Prairie Wind Transmission, LLC (Prairie Wind) through its ownership interest in Electric Transmission America, LLC. which is a 50/50 joint venture with Berkshire Hathaway Energy (formerly known as MidAmerican Energy) and AEP.

(c)

The Pioneer project consists of approximately 286 miles of new 765 kV transmission lines, which is estimated to cost $1.1 billion at completion. Pioneer is developing the first 66-mile segment jointly with Northern Indiana Public Service Company at a total estimated cost of $347 million. The projected completion date for the first 66-mile segment is June 2018. The projected completion dates for the remaining segments have not been determined.


(d)	AEP owns 87.5% of RITELine Indiana, LLC (RITELine IN) through its ownership interest in RITELine Transmission Development, LLC (RTD) and AEPTHCo. AEP owns 12.5% of RITELine Illinois, LLC (RITELine IL) through its ownership interest in RTD. RTD is a 50/50 joint venture with Exelon Transmission Company, LLC and AEPTHCo.


(e)	RITELine IN is a consolidated variable interest entity. RTD received an order from the FERC in October 2011 granting incentives for the RITELine IN and RITELine IL projects. The projects and other segments that are electrically equivalent in nature will continue to be submitted for consideration in the interregional planning process between PJM and MISO as dictated by emerging system needs.


(f)	AEP owns 86.5% of Transource Missouri, Transource West Virginia, Transource Maryland and Transource Pennsylvania through its ownership interest in Transource Energy, LLC (Transource). Transource is a joint venture with AEPTHCo and Great Plains Energy formed to pursue competitive transmission projects. AEPTHCo and Great Plains Energy own 86.5% and 13.5% of Transource, respectively.


(g)	The ROE represents the weighted average approved return on equity based on the costs of two projects developed by Transource Missouri; the $65 million Iatan-Nashua project (10.3%) and the $246 million Sibley-Nebraska City project (11.3%).


(h)	In August 2016, Transource Maryland and Transource Pennsylvania received approval from the PJM Interconnection Board to construct portions of a transmission project located in both Maryland and Pennsylvania. The project is expected to go in service in 2020.


(i)	In January 2018, Transource Maryland and Transource Pennsylvania received FERC approval of a settlement authorizing an ROE of 10.4%. This reflects a 9.9% base plus 0.5% RTO participation adder.

(j)

RITELine IN, Transource Missouri, Transource West Virginia, Transource Maryland and Transource Pennsylvania are consolidated joint ventures by AEP. Therefore, the investment value listed reflects applicable income taxes that are the responsibility of AEP. All other investments in this table are joint ventures that are not consolidated by AEP. Therefore, these investment values listed do not reflect income taxes that are the responsibility of AEP.

AEP’s joint ventures do not have employees. Business services for the joint ventures are provided by AEPSC and other AEP subsidiaries and the joint venture partners. During 2017, approximately 510 AEPSC employees and 283 operating company employees provided service to one or more joint ventures.

REGULATION

The State Transcos and the Transmission Joint Ventures located outside of ERCOT establish transmission rates annually through forward looking formula rate filings with the FERC pursuant to FERC-approved implementation protocols. The protocols include a transparent, formal review process to ensure the updated transmission rates are prudently incurred and reasonably calculated.

The State Transcos’ and the Transmission Joint Ventures’ (where applicable) rates are included in the respective OATT for PJM and SPP. An OATT is the FERC rate schedule that provides the terms and conditions for transmission and related services on a transmission provider’s transmission system. The FERC requires transmission providers such as PJM and SPP to offer transmission service to all eligible customers (for example, load-serving entities, power marketers, generators and customers) on a non-discriminatory basis.

The FERC-approved formula rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners in annual rate base filings with the FERC. The formula rates establish rates for a one-year period based on the current projects in-service and proposed projects for a defined timeframe. The formula rates also include a true-up calculation for the previous year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. PJM and SPP pay the transmission owners their ATRR for use of their facilities and bill transmission customers taking service under the PJM and SPP OATTs, based on the terms and conditions in the respective OATT for the service taken. Additionally, the State Transcos are subject to reliability standards promulgated by the North American Electric Reliability Corporation, with the approval of the FERC.

The formula rate mechanism allows for a return on equity of 11.49% based on a capital structure of up to 50% equity for APTCo, IMTCo, KTCo, OHTCo and WVTCo (the East Transcos). OKTCo and SWTCo (the West Transcos) are allowed a return on equity of 11.2% based on a capital structure of up to 50% equity. The authorized returns on equity for the State Transcos are commensurate with the FERC-authorized returns on equity in the PJM and SPP OATTs, respectively, for AEP’s utility subsidiaries. These returns have been challenged by parties in filings before the FERC.

In the annual rate base filings described above, the State Transcos in aggregate filed rate base totals of $3.8 billion for 2017, $3.2 billion for 2016 and $2.3 billion for 2015. The total transmission revenue requirements filed in the ATRR, including prior year over/under-recovery of revenue and associated carrying charges, for 2017, 2016, and 2015 was $690 million, $555 million and $363 million, respectively.

The rates of ETT, which is located in ERCOT, are determined by the PUCT. ETT sets its rates through a combination of base rate cases and interim Transmission Costs of Services (TCOS) filings. ETT may file interim TCOS filings semi-annually to update its rates to reflect changes in its net invested capital.

Effective March 2017, the Transmission Joint Ventures have approved returns on equity ranging from 9.6% to 12.8% based on equity capital structures ranging from 40% to 60%.

GENERATION & MARKETING

GENERAL

The AEP Generation & Marketing segment subsidiaries consist of competitive generating assets, a wholesale energy trading and marketing business and a retail supply and energy management business. The largest subsidiary in the Generation & Marketing segment is AGR. In January 2017, AGR sold 4,143 MWs of generation capacity to an unaffiliated third party and terminated a 1,186 MW unit power agreement. As of December 31, 2017, AGR owns 2,564 MWs of generating capacity. Other subsidiaries in this segment own or have the right to receive power from additional generation assets. See Item 2 – Properties for more information regarding the generation assets of the Generation & Marketing segment. AGR is a competitive generation subsidiary.

With respect to the wholesale energy trading and marketing business, AEP Generation & Marketing segment subsidiaries enter into short-term and long-term transactions to buy or sell capacity, energy and ancillary services in ERCOT, SPP, MISO and PJM. These subsidiaries sell power into the market and engage in power, natural gas and emissions allowances risk management and trading activities.

These activities primarily involve the purchase-and-sale of electricity (and to a lesser extent, natural gas and emissions allowances) under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, over-the-counter swaps and options. The majority of forward contracts are typically settled by entering into offsetting contracts. These transactions are executed with numerous counterparties or on exchanges.

With respect to the retail supply and energy management business, AEP Energy is a retail energy supplier that supplies electricity and/or natural gas to residential, commercial, and industrial customers. AEP Energy provides various energy solutions in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C. AEP Energy also provides demand-side management solutions nationwide. AEP Energy had approximately 410,000 customer accounts as of December 31, 2017.

As of December 31, 2017, AEP Energy Supply LLC owns 311 MWs of wind capacity in Texas and sells its energy entitlement to third parties or liquidates at market. During January 2018, a repowering agreement was entered into with a non-affiliated party that contributed full turbine sets in exchange for a 20% ownership interest. AEP Energy Supply, LLC retained 80% ownership (248 MW) of the wind capacity. AEP Renewables, LLC develops and/or acquires large scale renewable projects backed with long-term contracts with creditworthy counterparties. In 2017, AEP Renewables, LLC brought into service a 28 MW solar project in California and a 62 MW solar project in Nevada. The company also owns a 26 MW solar project in Utah that was brought into service in 2016.

AEP OnSite Partners, LLC works directly with wholesale and large retail customers to provide tailored solutions to reduce their energy costs based upon market knowledge, innovative applications of technology and deal structuring capabilities. The company targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions that create value for customers. AEP OnSite Partners, LLC pursues and develops behind the meter projects with creditworthy customers and appropriate agreements. As of December 31, 2017, AEP OnSite Partners, LLC owned projects operating in twelve states, including 63 MWs of installed solar capacity, and another 34 MWs of solar projects under construction in six states.

REGULATION

AGR is a public utility under the Federal Power Act, and is subject to the FERC’s exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, the FERC has the authority to grant or deny market-based rates for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable. The FERC granted AGR market-based rate authority in December 2013. The FERC’s jurisdiction over ratemaking also includes the authority to suspend the market-based rates of AGR

and set cost-based rates if the FERC subsequently determines that it can exercise market power, create barriers to entry or engage in abusive affiliate transactions. Periodically, AGR is required to file a market power update to show that it continues to meet the FERC’s standards with respect to generation market power and other criteria used to evaluate whether it continues to qualify for market-based rates. Other matters subject to the FERC jurisdiction include, but are not limited to, review of mergers, and dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility.

Specific operations of AGR are also subject to the jurisdiction of various other federal, state, regional and local agencies, including federal and state environmental protection agencies. AGR is also regulated by the PUCT for transactions inside ERCOT. Additionally, AGR is subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation, with the approval of the FERC.

COMPETITION

The AEP Generation & Marketing segment subsidiaries face competition for the sale of available power, capacity and ancillary services. The principal factors of impact are electricity and fuel prices, new market entrants, construction or retirement of generating assets by others and technological advances in power generation. Because most of AGR’s remaining generation is coal-fired, lower relative natural gas prices will favor competitors that have a higher concentration of natural gas fueled generation. Other factors impacting competitiveness include environmental regulation, transmission congestion or transportation constraints at or near generation facilities, inoperability or inefficiencies, outages and deactivations and retirements at generation facilities.

Technology advancements, increased demand for clean energy, changing consumer behaviors, low-priced and abundant natural gas, and regulatory and public policy reforms are among the catalysts for transformation within the industry that impact competition for AEP’s Generation & Marketing segment. AGR also competes with self-generation and with distributors of other energy sources, such as natural gas, fuel oil, renewables and coal, within their service areas. The primary factors in such competition are price, unit availability and the capability of customers to utilize sources of energy other than electric power.

Changes in regulatory policies and advances in newer technologies for batteries or energy storage, fuel cells, microturbines, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production. The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AGR’s competitiveness. The costs of photovoltaic solar cells in particular have continued to become increasingly competitive.

In the event that alternative generation resources are mandated, subsidized or encouraged through climate legislation or regulation or otherwise are economically competitive and added to the available generation supply, such resources could displace a higher marginal cost fossil plant, which could reduce the price at which market participants sell their electricity. These events could cause AGR to retire generating capacity prior to the end of its estimated useful life.

This segment’s retail operations provide competitive electricity and natural gas in deregulated retail energy markets in six states and Washington, D.C. Each such retail choice jurisdiction establishes its own laws and regulations governing its competitive market, and public utility commission communications and utility default service pricing can affect customer participation in retail competition. Sustained low natural gas and power prices, low market volatility and maturing competitive environments can adversely affect this business.

This segment also engages in procuring and selling output from renewable generation sources under long-term contracts to creditworthy counterparties. New sources are not acquired without first securing a long-term placement of such power. Existing sources do not face competitive exposure. Competitive unaffiliated suppliers of renewable or other generation could limit opportunities for future transactions for new sources and related output contracts.

SEASONALITY

Fuel Supply

The following table shows the generation sources by type, on an actual net generation (MWhs) basis, used by the Generation & Marketing segment, not including AEP Energy Partners’ offtake agreement from the Oklaunion generating unit:



	2017	2016	2015
Coal	85%	62%	66%
Natural Gas	8%	36%	32%
Renewables	7%	2%	2%

In January 2017, AEP sold three natural gas plants, Darby, Lawrenceburg and Waterford, to a nonaffiliated party. The sale resulted in a decrease in AEP’s natural gas supply in 2017, which increased AEP’s coal supply as a percentage of total fuel supply in 2017.

Coal and Consumables

AGR procures coal and consumables needed to burn the coal under a combination of purchasing arrangements including long-term and spot contracts with various producers and coal trading firms. As contracts expire, they are replaced, as needed, with contracts at market prices. Coal and consumable inventories remain adequate to meet generation requirements.

Management believes that AGR will be able to secure and transport coal and consumables of adequate quality and in adequate quantities to operate their coal fired units. AGR, through its contracts with third party transporters, has the ability to adequately move and store coal and consumables for use in its generating facilities. AGR plants consumed 4.6 million tons of coal in 2017.

The coal supplies at AGR plants vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, coal quality, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. AGR aims to maintain the coal inventory of its managed plants in the range of 15 to 40 days of full load burn. As of December 31, 2017, the coal inventory of AGR was above target.

Counterparty Risk Management

Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions. As of December 31, 2017, counterparties posted approximately $20 million in cash, cash equivalents or letters of credit with AEP for the benefit of AEP’s Generation & Marketing segment subsidiaries (while, as of that date, AEP’s Generation & Marketing segment subsidiaries posted approximately $97 million with counterparties and exchanges). Since open trading contracts are valued based on market prices of various commodities, exposures change daily. See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2017 Annual Reports, under the heading entitled Quantitative and Qualitative Disclosures About Market Risk for additional information.

Certain Power Agreements

As of December 31, 2017, the assets utilized in this segment included approximately 311 MWs of company-owned domestic wind power facilities, 177 MWs of domestic wind power from long-term purchase power agreements and 355 MWs of coal-fired capacity which was obtained through an agreement effective through 2027 that transfers the interest of AEP Texas in the Oklaunion Power Station to AEP Energy Partners, Inc. The power obtained from the Oklaunion Power Station is marketed and sold in ERCOT.

EXECUTIVE OFFICERS OF AEP

The following persons are executive officers of AEP. Their ages are given as of February 21, 2018. The officers are appointed annually for a one-year term by the board of directors of AEP.

Nicholas K. Akins

Chairman of the Board, President and Chief Executive Officer

Age 57

Chairman of the Board since January 2014, President since January 2011 and Chief Executive Officer since November 2011.

Lisa M. Barton

Executive Vice President - Transmission

Age 52

Executive Vice President - Transmission of AEPSC since August 2011.

Paul Chodak, III

Executive Vice President - Utilities

Age 54

Executive Vice President - Utilities since January 2017. Was President and Chief Operating Officer of I&M from July 2010 to December 2016.

David M. Feinberg

Executive Vice President, General Counsel and Secretary

Age 48

Executive Vice President since January 2013.

Lana L. Hillebrand

Executive Vice President and Chief Administrative Officer

Age 57

Chief Administrative Officer since December 2012 and Senior Vice President from December 2012 to December 2016.

Mark C. McCullough

Executive Vice President - Generation

Age 58

Executive Vice President - Generation of AEPSC since January 2011.

Charles R. Patton

Executive Vice President - External Affairs

Age 58

Executive Vice President - External Affairs since January 2017. Was President and Chief Operating Officer of APCo from June 2010 to December 2016.

Brian X. Tierney

Executive Vice President and Chief Financial Officer

Age 50

Executive Vice President and Chief Financial Officer since October 2009.

Charles E. Zebula

Executive Vice President - Energy Supply

Age 57

Executive Vice President - Energy Supply since January 2013. Was Senior Vice President - Investor Relations and Treasurer from September 2008 to December 2012.

ITEM 1A. RISK FACTORS

GENERAL RISKS OF REGULATED OPERATIONS

AEP may not be able to recover the costs of substantial planned investment in capital improvements and additions. (Applies to all Registrants)

AEP’s business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits, construction of additional transmission facilities, modernizing existing infrastructure as well as other initiatives. AEP’s public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates charged, affected AEP subsidiaries would not be able to recover the costs associated with their investments. This would cause financial results to be diminished.

Regulated electric revenues and earnings are dependent on federal and state regulation that may limit AEP’s ability to recover costs and other amounts. (Applies to all Registrants)

The rates customers pay to AEP regulated utility businesses are subject to approval by the FERC and the respective state utility commissions of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. In certain instances, AEP’s applicable regulated utility businesses may agree to negotiated settlements related to various rate matters that are subject to regulatory approval. AEP cannot predict the ultimate outcomes of any settlements or the actions by the FERC or the respective state commissions in establishing rates.

If regulated utility earnings exceed the returns established by the relevant commissions, retail electric rates may be subject to review and possible reduction by the commissions, which may decrease future earnings. Additionally, if regulatory bodies do not allow recovery of costs incurred in providing service on a timely basis, it could reduce future net income and cash flows and negatively impact financial condition. Similarly, if recovery or other rate relief authorized in the past is overturned or reversed on appeal, future earnings could be negatively impacted. Any regulatory action or litigation outcome that triggers a reversal of a regulatory asset or deferred cost generally results in an impairment to the balance sheet and a charge to the income statement of the company involved. For additional information, see Note 4 – Rate Matters and Note 12 – Income Taxes, of the notes to the financial statements, included in the 2017 Annual Reports.

AEP’s transmission investment strategy and execution are dependent on federal and state regulatory policy. (Applies to all Registrants)

Management expects that a growing portion of AEP’s earnings in the future will be derived from transmission investments and activities. FERC policy currently favors the expansion and updating of the transmission infrastructure within its jurisdiction. If the FERC were to adopt a different policy, if states were to limit or restrict such policies, or if transmission needs do not continue or develop as projected, AEP’s strategy of investing in transmission could be impacted. Management believes AEP’s experience with transmission facilities construction and operation gives AEP an advantage over other competitors in securing authorization to install, construct and operate new transmission lines and facilities. However, there can be no assurance that PJM, SPP or other RTOs will authorize new transmission projects or will award such projects to AEP.

Certain elements of AEP’s transmission formula rates have been challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on AEP’s business, financial condition, results of operations and cash flows. (Applies to all Registrants other than AEP Texas)

AEP provides transmission service under rates regulated by the FERC. The FERC has approved the cost-based formula rate templates used by AEP to calculate its respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the formula rates. All aspects of AEP’s rates accepted or approved by the FERC, including the formula rate templates, the rates of return on the actual equity portion

of its respective capital structures and the approved targeted capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative. In addition, interested parties may challenge the annual implementation and calculation by AEP of its projected rates and formula rate true up pursuant to its approved formula rate templates under AEP’s formula rate implementation protocols. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC will make appropriate prospective adjustments to them and/or disallow any of AEP’s inclusion of those aspects in the rate setting formula.

In October 2016, several parties filed a complaint with the FERC claiming that the base ROE used by certain AEP subsidiaries that operate in PJM, including the East Transcos, in calculating formula transmission rates under the PJM OATT, is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. In June 2017, a similar complaint was filed with the FERC claiming that the base ROE used by certain AEP subsidiaries that operate in SPP, including the West Transcos, in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to AEP, particularly if rates for delivered electricity increase substantially.

Recent changes in federal income tax policy may adversely affect cash flows, as well as credit ratings. (Applies to all Registrants)

Recently enacted United States federal income tax legislation significantly changed the Internal Revenue Code, including taxation of corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The legislation is unclear in certain respects and will require interpretations and implementing regulations by the Internal Revenue Service, as well as state income tax authorities, and the legislation could be subject to potential amendments and technical corrections, any of which could lessen or increase certain adverse impacts of the legislation. In addition, the regulatory treatment of the impacts of this legislation will be subject to the discretion of the FERC and state public utility commissions.

Although it is unclear when or how capital markets, credit rating agencies, the FERC or state public utility commissions may respond to this legislation, Management expects that certain financial metrics used by credit rating agencies, such as funds from operations-to-debt percentage, could be negatively impacted. In addition, state public utility commissions have started to engage with AEP’s utility subsidiaries to determine how any tax savings will be returned to customers. Management expects that AEP’s utility subsidiaries will return the tax benefits to customers, either through decreasing rates, increasing the amortization of regulatory assets, accelerating depreciation or offsetting other rate increases. The amount and the timing of any payments of tax benefits to be returned to customers will ultimately be determined by the regulators.

Management’s analysis and interpretation of this legislation is preliminary and ongoing. Based on Management’s current evaluation, limitations on interest deductions are not expected to be significant. Any amendments to the legislation or interpretations or implementing regulations by the IRS contrary to Management’s interpretation of the legislation could limit the ability to deduct the interest on some of the Registrants’ outstanding debt.

There may be other material adverse effects resulting from the legislation that have not yet been identified. If Management is unable to successfully take actions to manage any adverse impacts of the new tax legislation, or if additional interpretations, regulations, amendments or technical corrections exacerbate the adverse impacts of the legislation, the legislation could have an adverse effect on the Registrants’ financial condition, results of operations and cash flows and on the value of investments in debt securities and common stock. Any negative actions by credit rating agencies may make it more costly to issue future debt securities and could increase borrowing costs under existing credit facilities. For additional information, see Note 4 - Rate Matters and Note 12 - Income Taxes, of the Notes to Consolidated Financial Statements.

Changes in technology and regulatory policies may lower the value of electric utility facilities and franchises. (Applies to all Registrants)

AEP primarily generates electricity at large central facilities and delivers that electricity to customers over its transmission and distribution facilities to customers usually situated within an exclusive franchise. This method results in economies of scale and generally lower costs than newer technologies such as fuel cells and microturbines, and distributed generation using either new or existing technology. Other technologies, such as light emitting diodes (LEDs), increase the efficiency of electricity and, as a result, lower the demand for it. Changes in regulatory policies and advances in batteries or energy storage, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production and delivery. The ability to maintain relatively low cost, efficient and reliable operations, to establish fair regulatory mechanisms and to provide cost-effective programs and services to customers are significant determinants of AEP’s competitiveness. Further, in the event that alternative generation resources are mandated, subsidized or encouraged through legislation or regulation or otherwise are economically competitive and added to the available generation supply, such resources could displace a higher marginal cost generating units, which could reduce the price at which market participants sell their electricity.

AEP may not recover costs incurred to begin construction on projects that are canceled. (Applies to all Registrants)

AEP’s business plan for the construction of new projects involves a number of risks, including construction delays, nonperformance by equipment and other third party suppliers, and increases in equipment and labor costs. To limit the risks of these construction projects, AEP’s subsidiaries enter into equipment purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals and/or siting or environmental permits. If any of these projects are canceled for any reason, including failure to receive necessary regulatory approvals and/or siting or environmental permits, significant cancellation penalties under the equipment purchase orders and construction contracts could occur. In addition, if any construction work or investments have been recorded as an asset, an impairment may need to be recorded in the event the project is canceled.

AEP is exposed to nuclear generation risk. (Applies to AEP and I&M)

I&M owns the Cook Plant, which consists of two nuclear generating units for a rated capacity of 2,278 MWs, or about 7% of the generating capacity in the AEP System. AEP and I&M are, therefore, subject to the risks of nuclear generation, which include the following:


•	The potential harmful effects on the environment and human health due to an adverse incident/event resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials such as spent nuclear fuel.


•	Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations.


•	Uncertainties with respect to contingencies and assessment amounts triggered by a loss event (federal law requires owners of nuclear units to purchase the maximum available amount of nuclear liability insurance and potentially contribute to the coverage for losses of others).


•	Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.


•	Uncertainties related to AEP’s reliance on a vendor for manufacturing nuclear fuel and for providing specialized engineering services and parts.

There can be no assurance that I&M’s preparations or risk mitigation measures will be adequate if these risks are triggered.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants. In addition, although management has no reason to anticipate a serious nuclear incident at the Cook Plant, if an incident did occur, it could harm results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. Moreover, a major incident at any nuclear facility in the U.S. could require AEP or I&M to make material contributory payments.

Costs associated with the operation (including fuel), maintenance and retirement of nuclear plants continue to be more significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the operation of nuclear facilities. Costs also may include replacement power, any unamortized investment at the end of the useful life of the Cook Plant (whether scheduled or premature), the carrying costs of that investment and retirement costs. The ability to obtain adequate and timely recovery of costs associated with the Cook Plant is not assured.

Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. It intends to reorganize, not cease business operations. However, at the current stage of the bankruptcy process, it is unclear whether the company can successfully reorganize. In January 2018, Westinghouse issued a news release stating that it intends to sell all of its global business, including the portion of the nuclear business that contracts with Cook Plant. Any sale would require approval by the bankruptcy court. In the unlikely event Westinghouse rejects I&M’s contracts, or there is an interference with the sale process, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services.

The different regional power markets in which AEP subsidiaries compete have changing market and transmission structures, which could affect performance in these regions. (Applies to all Registrants)

Results are likely to be affected by differences in the market and transmission structures in various regional power markets. The rules governing the various regional power markets, including SPP and PJM, may also change from time to time which could affect costs or revenues. Because the manner in which RTOs will evolve remains unclear, management is unable to assess fully the impact that changes in these power markets may have on the business.

AEP could be subject to higher costs and/or penalties related to mandatory reliability standards. (Applies to all Registrants)

As a result of EPACT, owners and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with new reliability standards may subject AEP to higher operating costs and/or increased capital expenditures. While management expects to recover costs and expenditures from customers through regulated rates, there can be no assurance that the applicable commissions will approve full recovery in a timely manner. If AEP were found not to be in compliance with the mandatory reliability standards, AEP could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.

A substantial portion of AEP’s receivables is concentrated in a small number of REPs, and any delay or default in payment could adversely affect AEP’s cash flows, financial condition and results of operations. (Applies to AEP and AEP Texas)

AEP Texas collects receivables from the distribution of electricity from REPs that supply the electricity it distributes to its customers. As of December 31, 2017, AEP Texas did business with approximately 124 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for these services or could cause them to delay such payments. AEP Texas depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. Applicable PUCT regulations significantly limit the extent to which AEP Texas can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and AEP Texas thus remains at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. The PUCT enhanced the financial qualifications required of REPs that began selling power after January 1, 2009 and authorized utilities to defer bad debts resulting from defaults by REPs for recovery in a future rate case. In 2017, AEP Texas’ largest REP accounted for 18% of its operating revenue and its second largest REP accounted for 17% of its operating revenue. Any delay or default in payment by REPs could adversely affect cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments AEP Texas had received from such REP.

Actual capital investment in the State Transco’s may be lower than planned, which would cause a lower than anticipated rate base and would therefore result in lower revenues and earnings compared to management’s current expectations. (Applies to AEP and AEPTCo)

Each of the State Transcos’ rate base, revenues and earnings are determined in part by additions to property, plant and equipment and when those additions are placed in service. AEPTCo anticipates making significant capital investments over the next several years; however, the amounts could change significantly due to factors beyond its control. If the State Transcos’ capital investment and the resulting in-service property, plant and equipment are lower than anticipated for any reason, the State Transcos will have a lower than anticipated rate base, thus causing their revenue requirements and future earnings to be lower than anticipated.

Changes in energy laws, regulations or policies could impact AEP’s business, financial condition, results of operations and cash flows. (Applies to all Registrants)

Each of the Registrant Subsidiaries is regulated by either the FERC as a “public utility” under federal law or the PUCT and is a transmission owner in ERCOT, PJM or SPP. AEP cannot predict whether the approved rate methodologies for any of the Registrant Subsidiaries will be changed. In addition, the U.S. Congress periodically considers enacting energy legislation that could assign new responsibilities to the FERC, modify existing law or provide the FERC or another entity with increased authority to regulate transmission matters. AEP cannot predict whether, and to what extent, the Registrant Subsidiaries may be affected by any such changes in federal energy laws, regulations or policies in the future. While the Registrant Subsidiaries are subject to the PUCT’s or FERC’s exclusive jurisdiction for purposes of rate regulation, changes in state laws affecting other matters, such as transmission siting and construction, could limit investment opportunities.

RISKS RELATED TO MARKET, ECONOMIC OR FINANCIAL VOLATILITY AND OTHER RISKS

AEP’s financial performance may be adversely affected if AEP is unable to successfully operate facilities or perform certain corporate functions. (Applies to all Registrants)

Performance is highly dependent on the successful operation of generation, transmission and/or distribution facilities. Operating these facilities involves many risks, including:


•	Operator error and breakdown or failure of equipment or processes.


•	Operating limitations that may be imposed by environmental or other regulatory requirements.


•	Labor disputes.


•	Compliance with mandatory reliability standards, including mandatory cyber security standards.


•	Information technology failure that impairs AEP’s information technology infrastructure or disrupts normal business operations.


•	Information technology failure that affects AEP’s ability to access customer information or causes loss of confidential or proprietary data that materially and adversely affects AEP’s reputation or exposes AEP to legal claims.


•	Fuel or water supply interruptions caused by transportation constraints, adverse weather such as drought, non-performance by suppliers and other factors.


•	Catastrophic events such as fires, earthquakes, explosions, hurricanes, tornados, ice storms, terrorism (including cyber-terrorism), floods or other similar occurrences.


•	Fuel costs and related requirements triggered by financial stress in the coal industry.

Physical attacks or hostile cyber intrusions could severely impair operations, lead to the disclosure of confidential information and damage AEP’s reputation. (Applies to all Registrants)

AEP and its regulated utility businesses face physical security and cybersecurity risks as the owner-operators of generation, transmission and/or distribution facilities and as participants in commodities trading. AEP and its regulated utility businesses own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run these facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or AEP operations could view these computer systems, software or networks as targets for cyber attack. In addition, the electric utility business requires the collection of sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.

A security breach of AEP or its regulated utility businesses’ physical assets or information systems, interconnected entities in RTOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or subject AEP and its regulated utility businesses to financial harm associated with theft or inappropriate release of certain types of information, including sensitive customer, vendor, employee, trading or other confidential data. A successful cyber attack on the systems that control generation, transmission, distribution or other assets could severely disrupt business operations, preventing service to customers or collection of revenues. The breach of certain business systems could affect the ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to AEP’s reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. For these reasons, a significant cyber incident could reduce future net income and cash flows and negatively impact financial condition.

In an effort to reduce the likelihood and severity of cyber intrusions, AEP has a comprehensive cyber security program designed to protect and preserve the confidentiality, integrity and availability of data and systems. In addition, AEP is subject to mandatory cyber security regulatory requirements. However, cyber threats continue to evolve and adapt, and, as a result, there is a risk that AEP could experience a successful cyber attack despite current security posture and regulatory compliance efforts.

If AEP is unable to access capital markets on reasonable terms, it could reduce future net income and cash flows and negatively impact financial condition. (Applies to all Registrants)

AEP relies on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows. Volatility and reduced liquidity in the financial markets could affect AEP’s ability to raise capital and fund capital needs, including construction costs and refinancing maturing indebtedness. Certain sources of debt and equity capital expressed increasing unwillingness to invest in companies, such as AEP, that rely on fossil fuels. If sources of capital for AEP are reduced, capital costs could increase materially. Restricted access to capital markets and/or increased borrowing costs could reduce future net income and cash flows and negatively impact financial condition.

Downgrades in AEP’s credit ratings could negatively affect its ability to access capital. (Applies to all Registrants)

The credit ratings agencies periodically review AEP’s capital structure and the quality and stability of earnings and cash flows. Any negative ratings actions could constrain the capital available to AEP and could limit access to funding for operations. AEP’s business is capital intensive, and AEP is dependent upon the ability to access capital at rates and on terms management determines to be attractive. If AEP’s ability to access capital becomes significantly constrained, AEP’s interest costs will likely increase and could reduce future net income and cash flows and negatively impact financial condition.

AEP has no income or cash flow apart from dividends paid or other payments due from its subsidiaries. (Applies to AEP)

AEP is a holding company and has no operations of its own. Its ability to meet its financial obligations associated with its indebtedness and to pay dividends on its common stock is primarily dependent on the earnings and cash flows of its operating subsidiaries, primarily its regulated utilities, and the ability of its subsidiaries to pay dividends to, or repay loans from, AEP. Its subsidiaries are separate and distinct legal entities that have no obligation (apart from loans from AEP) to provide AEP with funds for its payment obligations, whether by dividends, distributions or other payments. Payments to AEP by its subsidiaries are also contingent upon their earnings and business considerations. AEP indebtedness and common stock dividends are structurally subordinated to all subsidiary indebtedness.

AEP’s operating results may fluctuate on a seasonal or quarterly basis and with general economic and weather conditions. (Applies to all Registrants)

Electric power generation is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. As a result, overall operating results in the future may fluctuate substantially on a seasonal basis. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could reduce future net income and cash flows and negatively impact financial condition. In addition, unusually extreme weather conditions could impact AEP’s results of operations in a manner that would not likely be sustainable.

Further, deteriorating economic conditions generally result in reduced consumption by customers, particularly industrial customers who may curtail operations or cease production entirely, while an expanding economic environment generally results in increased revenues. As a result, prevailing economic conditions may reduce future net income and cash flows and negatively impact financial condition.

Volatility in the securities markets, interest rates, and other factors could substantially increase defined benefit pension and other postretirement plan costs and the costs of nuclear decommissioning. (Applies to all Registrants and to AEP and I&M with respect to the costs of nuclear decommissioning)

The costs of providing pension and other postretirement benefit plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in actuarial assumptions, future government regulation, changes in life expectancy, and the frequency and amount of AEP’s required or voluntary contributions made to the plans. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund the pension and other postretirement plans, if not offset or mitigated by a decline in plan liabilities, could increase pension and other postretirement expense, and AEP could be required from time to time to fund the pension plan with significant amounts of cash. Such cash funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations. Additionally, I&M holds a significant amount of assets in its nuclear decommissioning trusts to satisfy obligations to decommission its nuclear plant. The rate of return on assets held in those trusts can significantly impact both the costs of decommissioning and the funding requirements for the trusts.

Failure to attract and retain an appropriately qualified workforce could harm results of operations. (Applies to all Registrants)

Certain events, such as an aging workforce without appropriate replacements, mismatch of skillset or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business. If AEP is unable to successfully attract and retain an appropriately qualified workforce, future net income and cash flows may be reduced.

Changes in the price of commodities, emission allowances for criteria pollutants and the costs of transport may increase AEP’s cost of producing power, impacting financial performance. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

AEP is exposed to changes in the price and availability of fuel (including coal and gas) and the price and availability to transport fuel. AEP has existing contracts of varying durations for the supply of fuel, but as these contracts end or if they are not honored, AEP may not be able to purchase fuel on terms as favorable as the current contracts. Similarly, AEP is exposed to changes in the price and availability of emission allowances. AEP uses emission allowances based on the amount of coal used as fuel and the reductions achieved through emission controls and other measures. As long as current environmental programs remain in effect, AEP has sufficient emission allowances to cover the majority of the projected needs for the next two years and beyond. If the Federal EPA attempts to further reduce interstate transport, and it is acceptable by the courts, additional costs may be incurred either to acquire additional allowances or to achieve further reductions in emissions. If AEP needs to obtain allowances, those purchases may not be on as favorable terms as those under the current environmental programs. AEP’s risks relative to the price and availability to transport coal include the volatility of the price of diesel which is the primary fuel used in transporting coal by barge.

Prices for coal, natural gas and emission allowances have shown material swings in the past. Changes in the cost of fuel, emission allowances or natural gas and changes in the relationship between such costs and the market prices of power could reduce future net income and cash flows and negatively impact financial condition.

In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to value trading and marketing transactions, and those differences may be material. As a result, as those transactions are marked to market, they may impact future results of operations and cash flows and impact financial condition.

AEP is subject to physical and financial risks associated with climate change. (Applies to all Registrants)

Climate change creates physical and financial risk. Physical risks from climate change may include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events. Customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.

Increased energy use due to weather changes may require AEP to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect financial condition through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions outside of the AEP service territory could also have an impact on revenues. AEP buys and sells electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on AEP’s own and/or other systems may raise electricity prices as AEP buys short-term energy to serve AEP’s own system, which would increase the cost of energy AEP provides to customers.

Severe weather impacts AEP’s service territories, primarily when thunderstorms, tornadoes, hurricanes, floods and snow or ice storms occur. To the extent the frequency of extreme weather events increases, this could increase AEP’s cost of providing service. Changes in precipitation resulting in droughts, water shortages or floods could adversely affect operations, principally the fossil fuel generating units. A negative impact to water supplies due to long-term drought conditions or severe flooding could adversely impact AEP’s ability to provide electricity to customers, as well as increase the price they pay for energy. AEP may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region’s economic health, it may also impact revenues. AEP’s financial performance is tied to the health of the regional economies AEP serves. The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of the communities within the AEP System.

Management cannot predict the outcome of the legal proceedings relating to AEP’s business activities. (Applies to all Registrants)

AEP is involved in legal proceedings, claims and litigation arising out of its business operations, the most significant of which are summarized in Note 6 of the Notes to Financial Statements entitled Commitments, Guarantees and Contingencies. Adverse outcomes in these proceedings could require significant expenditures that could reduce future net income and cash flows and negatively impact financial condition.

Disruptions at power generation facilities owned by third parties could interrupt the sales of transmission and distribution services. (Applies to AEP and AEP Texas)

AEP Texas transmits and distributes electric power that the REPs obtain from power generation facilities owned by third parties. If power generation is disrupted or if power generation capacity is inadequate, sales of transmission and distribution services may be diminished or interrupted, and results of operations, financial condition and cash flows could be adversely affected.

Hazards associated with high-voltage electricity transmission may result in suspension of AEP’s operations or the imposition of civil or criminal penalties. (Applies to all Registrants)

AEP operations are subject to the usual hazards associated with high-voltage electricity transmission, including explosions, fires, inclement weather, natural disasters, mechanical failure, unscheduled downtime, equipment interruptions, remediation, chemical spills, discharges or releases of toxic or hazardous substances or gases and other environmental risks. The hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties. AEP maintains property and casualty insurance, but AEP is not fully insured against all potential hazards incident to AEP’s business, such as damage to poles, towers and lines or losses caused by outages.

Management is considering strategic alternatives for a portion of interest in the Oklaunion Power Station and may incur losses as a result. (Applies to AEP, AEP Texas and PSO)

Management is evaluating strategic alternatives for the respective interests of AEP Texas and PSO in the Oklaunion Power Station. AEPEP also has interest in the Oklaunion Power Station through its PPA with AEP Texas in which AEPEP receives the entire output of AEP Texas’ share of the Oklaunion Power Station through December 2027. Management has not made a decision regarding the potential alternatives, nor have they set a specific timeframe for a decision. Certain of these alternatives could result in an impairment, a loss and/or could reduce future net income and cash flow and harm financial condition.

AEPTCo depends on its affiliates in the AEP System for a substantial portion of its revenues. (Applies to AEPTCo)

AEPTCo’s principal transmission service customers are its affiliates in the AEP System. Management expects that these affiliates will continue to be AEPTCo’s principal transmission service customers for the foreseeable future. For the year ended December 31, 2017, its affiliates were responsible for approximately 80% of the consolidated transmission revenues of AEPTCo.

Most of the real property rights on which the assets of AEPTCo are situated result from affiliate license agreements and are dependent on the terms of the underlying easements and other rights of its affiliates. (Applies to AEPTCo)

AEPTCo does not hold title to the majority of real property on which its electric transmission assets are located. Instead, under the provisions of certain affiliate contracts, it is permitted to occupy and maintain its facilities upon real property held by the respective AEP System utility affiliate that overlay its operations. The ability of AEPTCo to continue to occupy such real property is dependent upon the terms of such affiliate contracts and upon the underlying real property rights of these utility affiliates, which may be encumbered by easements, mineral rights and other similar encumbrances that may affect the use of such real property. AEP can give no assurance that (a) the relevant AEP System utility affiliates will continue to be affiliates of AEPTCo, (b) suitable replacement arrangements can be obtained in the event that the relevant AEP System utility affiliates are not its affiliates, and (c) the underlying easements and other rights are sufficient to permit AEPTCo to operate its assets in a manner free from interruption.

RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Costs of compliance with existing environmental laws are significant. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

Operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. A majority of the electricity generated by the AEP System is produced by the combustion of fossil fuels. Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generation plants are subject to increased regulations, controls and mitigation expenses. Compliance with these legal requirements requires AEP to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at all AEP facilities and could cause AEP to retire generating capacity prior to the end of its estimated useful life. Costs of compliance

with environmental regulations could reduce future net income and negatively impact financial condition, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed or additional substances become regulated. Although AEP typically recovers expenditures for pollution control technologies, replacement generation, undepreciated plant balances and associated operating costs from customers through regulated rates in regulated jurisdictions, there can be no assurance that AEP will recover the remaining costs associated with such plants. Failure to recover these costs could reduce future net income and cash flows and possibly harm financial condition.

Regulation of CO₂ emissions could materially increase costs to AEP and its customers or cause some electric generating units to be uneconomical to operate or maintain. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

In 2014, the Federal EPA issued standards for new, modified and reconstructed units, and a guideline for the development of state implementation plans that would reduce carbon emissions from existing utility units. The standards and guidelines were finalized in 2015, and have been challenged by several dozen states as well as industry groups and other stakeholders. The U.S. Supreme Court has stayed the implementation of the guidelines for existing sources, known as the Clean Power Plan, until a final decision is issued by the courts. In 2017, the Federal EPA issued a proposal to repeal the Clean Power Plan, and an advance notice of proposed rulemaking seeking information that should be considered in the development of new emission guidelines.

CO₂ standards could require significant increases in capital expenditures and operating costs and could impact the dates for retirement of AEP’s coal-fired units. AEP typically recovers costs of complying with new requirements such as the potential CO₂ and other greenhouse gases emission standards from customers through regulated rates in regulated jurisdictions.

Courts adjudicating nuisance and other similar claims in the future may order AEP to pay damages or to limit or reduce emissions. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

In the past, there have been several cases seeking damages based on allegations of federal and state common law nuisance in which AEP, among others, were defendants. In general, the actions allege that emissions from the defendants’ power plants constitute a public nuisance. The plaintiffs in these actions generally seek recovery of damages and other relief. If future actions are resolved against AEP, substantial modifications of AEP’s existing coal-fired power plants could be required and AEP might be required to limit or reduce emissions. Such remedies could require AEP to purchase power from third parties to fulfill AEP’s commitments to supply power to AEP customers. This could have a material impact on costs. In addition, AEP could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay damages or penalties and/or halt operations. While management believes such costs should be recoverable from customers as costs of doing business in AEP jurisdictions where generation rates are set on a cost of service basis, without such recovery, those costs could reduce future net income and cash flows and harm financial condition. Moreover, results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.

AEP’s results of operations and cash flows may be negatively affected by a lack of growth or slower growth in the number of customers, or decline in customer demand. (Applies to all Registrants)

Growth in customer accounts and growth of customer usage each directly influence demand for electricity and the need for additional power generation and delivery facilities. Customer growth and customer usage are affected by a number of factors outside the control of AEP, such as mandated energy efficiency measures, demand-side management goals, distributed generation resources and economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity.

Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to further reduce energy consumption. Additionally, technological advances or other improvements in or applications of technology could lead to declines in per capita energy consumption. Some or all of these factors, could impact the demand for electricity.

Commodity trading and marketing activities are subject to inherent risks which can be reduced and controlled but not eliminated. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

AEP routinely has open trading positions in the market, within guidelines set by AEP, resulting from the management of AEP’s trading portfolio. To the extent open trading positions exist, fluctuating commodity prices can improve or diminish financial results and financial position.

AEP’s power trading activities also expose AEP to risks of commodity price movements. To the extent that AEP’s power trading does not hedge the price risk associated with the generation it owns, or controls, AEP would be exposed to the risk of rising and falling spot market prices.

In connection with these trading activities, AEP routinely enters into financial contracts, including futures and options, over-the counter options, financially-settled swaps and other derivative contracts. These activities expose AEP to risks from price movements. If the values of the financial contracts change in a manner AEP does not anticipate, it could harm financial position or reduce the financial contribution of trading operations.

Parties with whom AEP has contracts may fail to perform their obligations, which could harm AEP’s results of operations. (Applies to all Registrants)

AEP sells power from its generation facilities into the spot market and other competitive power markets on a contractual basis. AEP also enters into contracts to purchase and sell electricity, natural gas, emission allowances and coal as part of its power marketing and energy trading operations. AEP is exposed to the risk that counterparties that owe AEP money or the delivery of a commodity, including power, could breach their obligations. Should the counterparties to these arrangements fail to perform, AEP may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices that may exceed AEP’s contractual prices, which would cause financial results to be diminished and AEP might incur losses. Although estimates take into account the expected probability of default by a counterparty, actual exposure to a default by a counterparty may be greater than the estimates predict.

AEP relies on electric transmission facilities that AEP does not own or control. If these facilities do not provide AEP with adequate transmission capacity, AEP may not be able to deliver wholesale electric power to the purchasers of AEP’s power. (Applies to all Registrants)

AEP depends on transmission facilities owned and operated by other nonaffiliated power companies to deliver the power AEP sells at wholesale. This dependence exposes AEP to a variety of risks. If transmission is disrupted, or transmission capacity is inadequate, AEP may not be able to sell and deliver AEP wholesale power. If a region’s power transmission infrastructure is inadequate, AEP’s recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

The FERC has issued electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales. Although these initiatives are designed to encourage wholesale market transactions, access to transmission systems may not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable. Management also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.

OVEC may require additional liquidity and other capital support. (Applies to AEP, APCo, I&M and OPCo)

AEP and several nonaffiliated utility companies own OVEC. The Inter-Company Power Agreement (ICPA) defines the rights and obligations and sets the power participation ratio of the parties to it. Under the ICPA, parties are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MW) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. If a party fails to make payments owed by it under the ICPA, OVEC may not have sufficient funds to honor its payment obligations, including its ongoing operating expenses as well as its indebtedness. OVEC has outstanding indebtedness of approximately $1.4 billion.

In late 2016, a nonaffiliated party to the ICPA announced its intention to exit its merchant business and that it may pursue restructuring or bankruptcy. This party’s aggregate power participation ratio is approximately 8% under the ICPA. Presently, this party has yet to pursue restructuring or bankruptcy. However, as a result of this announcement and other related developments, Moody’s downgraded OVEC’s rating with a negative outlook for possible downgrade, while Fitch and S&P have revised OVEC’s outlook to negative.

If OVEC does not have sufficient funds to honor its payment obligations, there is risk that APCo, I&M and/or OPCo may need to make payments in addition to their power participation ratio payments. Further, if OVEC’s indebtedness is accelerated for any reason, there is risk that APCo, I&M and/or OPCo may be required to pay some or all of such accelerated indebtedness in amounts equal to their aggregate power participation ratio of 43.47%. Also, as a result of the credit rating agencies’ actions, OVEC’s ability to access capital markets on terms as favorable as previously may diminish and its financing costs may rise.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

GENERATION FACILITIES

As of December 31, 2017 the AEP System owned (or leased where indicated) generation plants, with locations and net maximum power capabilities (winter rating) are shown in the following tables:

Vertically Integrated Utilities Segment



AEGCo
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
Rockport, Units 1 and 2 – 50% of each (a)	2	IN	Steam - Coal	1,310	1984


(a)	Rockport Plant, Unit 2 is leased.



AEP Texas
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
Oklaunion (a)	1	TX	Steam - Coal	355	1986


(a)	Jointly-owned with PSO and non-affiliated entities. Figures presented reflect only the portion owned by AEP Texas.



APCo
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
Buck	3	VA	Hydro	9	1912
Byllesby	4	VA	Hydro	22	1912
Claytor	4	VA	Hydro	75	1939
Leesville	2	VA	Hydro	50	1964
London	3	WV	Hydro	14	1935
Marmet	3	WV	Hydro	14	1935
Niagara	2	VA	Hydro	2	1906
Winfield	3	WV	Hydro	15	1938
Ceredo	6	WV	Natural Gas	516	2001
Dresden	3	OH	Natural Gas	613	2012
Smith Mountain	5	VA	Pumped Storage	615	1965
Amos	3	WV	Steam - Coal	2,930	1971
Mountaineer	1	WV	Steam - Coal	1,320	1980
Clinch River	2	VA	Steam - Natural Gas	465	1958
Total MWs				6,660



I&M
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
Berrien Springs	12	MI	Hydro	6	1908
Buchanan	10	MI	Hydro	3	1919
Constantine	4	MI	Hydro	1	1921
Elkhart	3	IN	Hydro	3	1913
Mottville	4	MI	Hydro	2	1923
Twin Branch Hydro	8	IN	Hydro	5	1904
Deer Creek Solar Farm	NA	IN	Solar	3	2016
Olive Solar Farm	NA	IN	Solar	5	2016
Twin Branch Solar Farm	NA	IN	Solar	3	2016
Watervliet	NA	MI	Solar	5	2016
Rockport (Units 1 and 2, 50% of each) (a)	2	IN	Steam - Coal	1,310	1984
Cook	2	MI	Steam - Nuclear	2,278	1975
Total MWs				3,624

NA Not applicable.


(a)	Rockport Plant, Unit 2 is leased.

The following table provides operating information related to the Cook Plant:



	Cook Plant
	Unit 1		Unit 2
Year Placed in Operation	1975		1978
Year of Expiration of NRC License	2034		2037
Nominal Net Electrical Rating in MWs	1,084		1,194
Annual Capacity Utilization
2017	76.5	%	98.8	%
2016	87.3	%	72.5	%
2015	82.4	%	89.7	%



KPCo
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
Mitchell (a)	2	WV	Steam - Coal	780	1971
Big Sandy	1	KY	Steam - Natural Gas	280	1963
Total MWs				1,060


(a)	KPCo owns a 50% interest in the Mitchell Plant units. WPCo owns the remaining 50%. Figures presented reflect only the portion owned by KPCo.



PSO
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
Comanche	3	OK	Natural Gas	248	1973
Riverside, Units 3 and 4	2	OK	Natural Gas	160	2008
Southwestern, Units 4 and 5	2	OK	Natural Gas	170	2008
Weleetka	3	OK	Natural Gas	185	1975
Northeastern, Unit 1	1	OK	Natural Gas	472	1961
Northeastern, Unit 3	1	OK	Steam - Coal	469	1979
Oklaunion (a)	1	TX	Steam - Coal	105	1986
Northeastern, Unit 2	1	OK	Steam - Natural Gas	434	1961
Riverside, Units 1 and 2	2	OK	Steam - Natural Gas	907	1974
Southwestern, Units 1, 2 and 3	3	OK	Steam - Natural Gas	465	1952
Tulsa	2	OK	Steam - Natural Gas	319	1956
Total MWs				3,934


(a)	Jointly-owned with AEP Texas and non-affiliated entities. Figures presented reflect only the portion owned by PSO.



SWEPCo
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
Mattison	4	AR	Natural Gas	315	2007
Stall	3	LA	Natural Gas	534	2010
Flint Creek (a)	1	AR	Steam - Coal	264	1978
Turk (a)	1	AR	Steam - Coal	477	2012
Welsh	2	TX	Steam - Coal	1,053	1977
Dolet Hills (a)	1	LA	Steam - Lignite	257	1986
Pirkey (a)	1	TX	Steam - Lignite	580	1985
Arsenal Hill	1	LA	Steam - Natural Gas	110	1960
Knox Lee	4	TX	Steam - Natural Gas	475	1950
Lieberman	3	LA	Steam - Natural Gas	242	1947
Lone Star	1	TX	Steam - Natural Gas	50	1954
Wilkes	3	TX	Steam - Natural Gas	893	1964
Total MWs				5,250


(a)	Jointly-owned with nonaffiliated entity(ies). Figures presented reflect only the portion owned by SWEPCo. The Arkansas jurisdictional portion of SWEPCo’s interest in Turk Plant is not in rate base.



WPCo
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
Mitchell (a)	2	WV	Steam - Coal	780	1971


(a)	17.5% of WPCo’s interest in the Mitchell Plant units is not in rate base. KPCo owns the remaining 50%. Figures presented reflect only the portion owned by WPCo.

Generation & Marketing Segment



AGR
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
Racine	2	OH	Hydro	48	1982
Cardinal	1	OH	Steam - Coal	595	1967
Conesville (a) (b)	3	OH	Steam - Coal	1,471	1957
Stuart (a) (c) (d)	4	OH	Steam - Coal	450	1971
Total MWs				2,564


(a)	Jointly-owned with nonaffiliated entities. Figures presented reflect only the portion owned by AGR.


(b)	In May 2017, AEP completed the purchase of Dynegy Corporation’s ownership share of Conesville Plant, Unit 4.


(c)	Stuart Plant, Unit 1 was mothballed in October 2017.


(d)	Stuart Plant is scheduled for retirement in 2018.



Renewable Power
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs) (a)	Year Plant Commissioned
Trent Mesa	100	TX	Wind	150	2001
Desert Sky	107	TX	Wind	161	2001
Total MWs				311


(a)	Reflects ownership as of December 31,2017. Effective January 16, 2018, 20.1% of each entity was transferred to a nonaffiliate partner in exchange for their contribution of full turbine sets to each project. As a result, these subsidiaries became joint ventures.

As of December 31, 2017, the Generation & Marketing segment held approximately 180 MWs of solar power in the states of California, Colorado, Florida, Hawaii, Minnesota, Nevada, New Hampshire, New Jersey, New Mexico, New York, Ohio, Texas, Utah and Vermont.

In addition to the AGR and Renewable Power generation set forth above, a subsidiary in the Generation & Marketing segment has contractual rights through 2027 from AEP Texas to 355 MWs from the Oklaunion Power Station, a coal-fired unit located in Vernon, TX. AEP Texas co-owns the Oklaunion Power Station with PSO and several non-affiliated entities.

TRANSMISSION AND DISTRIBUTION FACILITIES

The following tables set forth the total overhead circuit miles of transmission and distribution lines of the AEP System and its operating companies.

Vertically Integrated Utilities Segment



		Total Overhead Circuit Miles of Transmission and Distribution Lines
APCo		51,731
I&M		21,667
KGPCo		1,404
KPCo		11,164
PSO		18,460
SWEPCo		26,053
WPCo		1,743
Total Circuit Miles		132,222

Transmission and Distribution Utilities Segment



		Total Overhead Circuit Miles of Transmission and Distribution Lines
OPCo		45,162
AEP Texas		45,717
Total Circuit Miles		90,879

AEP Transmission Holdco Segment

The following table sets forth the total overhead circuit miles of transmission lines of certain wholly-owned and joint venture-owned entities:



	Total Overhead Circuit Miles of Transmission Lines
ETT	1,772
IMTCo	216
OHTCo	567
OKTCo	500
WVTCo	155
Prairie Wind Transmission	216
Transource Missouri	167
Total Circuit Miles	3,593

TITLE TO PROPERTY

The AEP System’s generating facilities are generally located on lands owned in fee simple. The greater portion of the transmission and distribution lines of the AEP System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority. The rights of AEP’s public utility subsidiaries in the realty on which their facilities are located are considered adequate for use in the conduct of their business. Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties. AEP’s public utility subsidiaries generally have the right of eminent domain which permits them, if necessary, to acquire, perfect or secure titles to or easements on privately held lands used or to be used in their utility operations. Legislation in Ohio and Virginia has restricted the right of eminent domain previously granted for power generation purposes.

SYSTEM TRANSMISSION LINES AND FACILITY SITING

Laws in the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Tennessee, Texas, Virginia and West Virginia require prior approval of sites of generating facilities and/or routes of high-voltage transmission lines. AEP has experienced delays and additional costs in constructing facilities as a result of proceedings conducted pursuant to such statutes and in proceedings in which AEP’s operating companies have sought to acquire rights-of-way through condemnation. These proceedings may result in additional delays and costs in future years.

CONSTRUCTION PROGRAM

With input from its state utility commissions, the AEP System continuously assesses the adequacy of its transmission, distribution, generation and other facilities to plan and provide for the reliable supply of electric power and energy to its customers. In this assessment process, assumptions are continually being reviewed as new information becomes available and assessments and plans are modified, as appropriate. AEP forecasts approximately $6 billion of construction expenditures for 2018. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather and the ability to access capital. For additional information on AEP’s construction program, see Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2017 Annual Reports, under the heading entitled Budgeted Construction Expenditures.

POTENTIAL UNINSURED LOSSES

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to AEP’s generation plants and costs of replacement power. Unless allowed to be recovered through rates, future losses or liabilities which are not completely insured could reduce net income and impact the financial conditions of AEP and other AEP System companies. For risks related to owning a nuclear generating unit, see Note 6 to the financial statements entitled Commitments, Guarantees and Contingencies under the heading Nuclear Contingencies for information with respect to nuclear incident liability insurance.

ITEM 3. LEGAL PROCEEDINGS

For a discussion of material legal proceedings, see Note 6 to the financial statements, entitled Commitments, Guarantees and Contingencies, incorporated by reference in Item 8.

ITEM 4. MINE SAFETY DISCLOSURE

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of Dolet Hills Lignite Company (DHLC), a wholly-owned lignite mining subsidiary of SWEPCo, is subject to the provisions of the Mine Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarter ended December 31, 2017.

PART II

ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

AEP

In addition to the discussion below, the remaining information required by this item is incorporated herein by reference to the material under AEP Common Stock and Dividend Information and Note 14 to the financial statements entitled Financing Activities under the heading Dividend Restrictions in the 2017 Annual Report.

AEP Texas, APCo, I&M, OPCo, PSO and SWEPCo

The common stock of these companies is held solely by AEP. The information regarding the amounts of cash dividends on common stock paid by these companies to AEP during 2017, 2016 and 2015 are incorporated by reference to the material under Statements of Changes in Common Shareholder’s Equity and Note 14 to the financial statements entitled Financing Activities under the heading Dividend Restrictions in the 2017 Annual Reports.

AEPTCo

AEP owns the entire interest in AEPTCo through its wholly-owned subsidiary AEP Transmission Holding Company, LLC.

During the quarter ended December 31, 2017, neither AEP nor its publicly-traded subsidiaries purchased equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act.

ITEM 6. SELECTED FINANCIAL DATA

AEP

The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 2017 Annual Reports.

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(a). Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2017 Annual Reports.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

AEP

The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2017 Annual Reports.

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

The information required by this item is incorporated herein by reference to the financial statements and financial statement schedules described under Item 15 herein.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Information required by this item is set forth under the caption Proposal to Ratify the Appointment of the Independent Registered Public Accounting Firm in the 2018 Proxy Statement, which is incorporated by reference into this item.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

During 2017, management, including the principal executive officer and principal financial officer of each of American Electric Power Company, Inc. (“AEP”), AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company (each a “Registrant” and collectively the “Registrants”) evaluated each respective Registrant’s disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrant that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized, and reported within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to each Registrant’s management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of December 31, 2017, the principal executive officer and financial officer of each of the Registrants concluded that the disclosure controls and procedures in place were effective at the reasonable assurance level. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

Changes in Internal Control over Financial Reporting

There have been no changes in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter 2017 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

Internal Control over Financial Reporting

See Management’s Report on Internal Control over Financial Reporting for each Registrant under Item 8. As discussed in that report, management assessed and reported on the effectiveness of each Registrant’s internal control over financial reporting as of December 31, 2017. As a result of that assessment, management concluded that each Registrant’s internal control over financial reporting was effective as of December 31, 2017.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

AEP

Directors, Director Nomination Process and Audit Committee

Certain of the information called for in this Item 10, including the information relating to directors, is incorporated herein by reference to AEP’s definitive proxy information statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to 2018 Annual Meeting of Shareholders (the 2018 Annual Meeting) including under the captions “Election of Directors,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “AEP’s Board of Directors and Committees,” “Directors” and “Shareholder Nominees for Directors.”

Executive Officers

Reference also is made to the information under the caption Executive Officers of AEP in Part I, Item 1 of this report.

Code of Ethics

AEP’s Principles of Business Conduct is the code of ethics that applies to AEP’s Chief Executive Officer, Chief Financial Officer and principal accounting officer. The Principles of Business Conduct is available on AEP’s website at www.aep.com. The Principles of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Investor Relations, American Electric Power Company, Inc., 1 Riverside Plaza, Columbus, Ohio 43215.

If any substantive amendments to the Principles of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Principles of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or principal accounting officer, AEP will disclose the nature of such amendment or waiver on AEP’s website, www.aep.com, or in a report on Form 8-K.

Section 16(a) Beneficial Ownership Reporting Compliance

The information required by this item is incorporated herein by reference to information contained in the definitive proxy statement of AEP for the 2018 Annual Meeting.

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

ITEM 11. EXECUTIVE COMPENSATION

AEP

The information called for by this Item 11 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2018 Annual Meeting including under the captions “Compensation Discussion and Analysis,” “Executive Compensation”, “Director Compensation” and “2017 Director Compensation Table”. The information set forth under the subcaption “Human Resources Committee Report” and “Audit Committee Report” should not be deemed filed nor should it be incorporated by reference into any other filing under the Securities Act of 1933, as amended, or the Exchange Act except to the extent AEP specifically incorporates such report by reference therein.

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

AEP

The information relating to Security Ownership of Certain Beneficial Owners is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to 2018 Annual Meeting under the caption “Share Ownership of Certain Beneficial Owners and Management” and “Share Ownership of Directors and Executive Officers.”

EQUITY COMPENSATION PLAN INFORMATION

The following table summarizes the ability of AEP to issue common stock pursuant to equity compensation plans as of December 31, 2017:



Plan Category	Number of Securities to be Issued upon Exercise of Outstanding Options Warrants and Rights (a)		Weighted Average Exercise Price of Outstanding Options, Warrants and Rights (b)	Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans
Equity Compensation Plans Approved by Security Holders	1,705,059		—	9,011,946
Equity Compensation Plans Not Approved by Security Holders	—		—	—
Total	1,705,059	1,705,059	—	9,011,946

(a)

The balance includes unvested 2017 performance units and restricted stock units as well as vested performance units deferred as AEP career shares, all of which will be settled and paid in shares of AEP common stock. Performance units, restricted stock units and AEP career shares that are settled and paid in cash are not included. For performance units, the total includes the target number of shares that could be granted if performance meets target objectives. The number of securities that would be granted, with respect to performance units, if performance meets the maximum payout level, is two times the amount included in this total.


(b)	No consideration is required from participants for the exercise or vesting of any outstanding AEP equity compensation awards.

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

AEP

The information called for by this Item 13 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2018 Annual Meeting under the captions “Transactions with Related Persons” and “Director Independence.”

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

AEP

The information called for by this Item 14 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2018 Annual Meeting under the captions “Audit and Non-Audit Fees,” “Audit Committee Report” and “Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Auditor.”

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Each of the above is a wholly-owned subsidiary of AEP and does not have a separate audit committee. A description of the AEP Audit Committee pre-approval policies, which apply to these companies, is contained in the definitive proxy statement of AEP for the 2018 Annual Meeting of shareholders. The following table presents directly billed fees for professional services rendered by Deloitte & Touche LLP for the audit of these companies’ annual financial statements for the year ended December 31, 2016, and fees directly billed for other services rendered by Deloitte & Touche LLP during those periods. Deloitte & Touche LLP also provides additional professional and other services to the AEP System, the cost of which may ultimately be allocated to these companies though not billed directly to them. For a description of these fees and services, see the description of principal accounting fees and services for AEP, above.



	2016
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
Audit Fees	$	780,549	$	692,187	$	2,202,328	$	1,691,802	$	1,184,577	$	699,346	$	1,286,154
Audit-Related Fees	123,066		20,308		47,582		10,661		47,291		501		686
Tax Fees	11,231		—		22,576		18,747		13,526		8,200		13,991
All Other Fees	27,264		17,520		36,254		28,797		23,548		21,813		29,903
Total	$	942,110	$	730,015	$	2,308,740	$	1,750,007	$	1,268,942	$	729,860	$	1,330,734

The following table presents directly billed fees for professional services rendered by PricewaterhouseCoopers LLP for the audit of these companies’ annual financial statements for the years ended December 31, 2017, and fees directly billed for other services rendered by PricewaterhouseCoopers LLP during those periods. PricewaterhouseCoopers LLP also provides additional professional and other services to the AEP System, the cost of which may ultimately be allocated to these companies though not billed directly to them. For a description of these fees and services, see the description of principal accounting fees and services for AEP above.



	2017
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
Audit Fees	$	1,081,882	$	947,509	$	1,756,776	$	1,503,971	$	1,042,136	$	654,569	$	1,071,925
Audit-Related Fees	76,000		—		45,738		7,738		45,738		7,738		55,738
Total	$	1,157,882	$	947,509	$	1,802,514	$	1,511,709	$	1,087,874	$	662,307	$	1,127,663

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are filed as a part of this report:


1.	FINANCIAL STATEMENTS:

The following financial statements have been incorporated herein by reference pursuant to Item 8.

AEP and Subsidiary Companies:

Reports of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2017, 2016 and 2015; Consolidated Statements of Changes in Equity for the years ended December 31, 2017, 2016 and 2015; Consolidated Balance Sheets as of December 31, 2017 and 2016; Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015; Notes to Financial Statements of Registrants.

AEP Texas, APCo, I&M and OPCo:

Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2017, 2016 and 2015; Consolidated Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2017, 2016 and 2015; Consolidated Balance Sheets as of December 31, 2017 and 2016; Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015; Notes to Financial Statements of Registrants; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.

AEPTCo:

Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015; Consolidated Statements of Changes in Member’s Equity for the years ended December 31, 2017, 2016 and 2015; Consolidated Balance Sheets as of December 31, 2017 and 2016; Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015; Notes to Financial Statements of Registrants; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.

PSO:

Statements of Income for the years ended December 31, 2017, 2016 and 2015; Statements of Comprehensive Income (Loss) for the years ended December 31, 2017, 2016 and 2015; Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2017, 2016 and 2015; Balance Sheets as of December 31, 2017 and 2016; Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015; Notes to Financial Statements of Registrants; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.

SWEPCo:

Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2017, 2016 and 2015; Consolidated Statements of Changes in Equity for the years ended December 31, 2017, 2016 and 2015; Consolidated Balance Sheets as of December 31, 2017 and 2016; Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015; Notes to Financial Statements of Registrants; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.



2. FINANCIAL STATEMENT SCHEDULES:		Page Number
Financial Statement Schedules are listed in the Index of Financial Statement Schedules. (Certain schedules have been omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable). Reports of Independent Registered Public Accounting Firm.		S-1

3. EXHIBITS:
Exhibits for AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference.		E-1

SIGNATURES



	American Electric Power Company, Inc.

	By:	/s/ Brian X. Tierney
		(Brian X. Tierney, Executive Vice President
		and Chief Financial Officer)

Date: February 22, 2018



Signature		Title	Date

(i)	Principal Executive Officer:

	/s/ Nicholas K. Akins	Chairman of the Board, Chief Executive Officer and Director	February 22, 2018
	(Nicholas K. Akins)	Chairman of the Board, Chief Executive Officer and Director

(ii)	Principal Financial Officer:

	/s/ Brian X. Tierney	Executive Vice President and Chief Financial Officer	February 22, 2018
	(Brian X. Tierney)	Executive Vice President and Chief Financial Officer

(iii)	Principal Accounting Officer:

	/s/ Joseph M. Buonaiuto	Senior Vice President, Controller and Chief Accounting Officer	February 22, 2018
	(Joseph M. Buonaiuto)

(iv)	A Majority of the Directors:

	*Nicholas K. Akins
	*David J. Anderson
	*J. Barnie Beasley, Jr.
	*Ralph D. Crosby, Jr.
	*Linda A. Goodspeed
	*Thomas E. Hoaglin
	*Sandra Beach Lin
	*Richard C. Notebaert
	*Lionel L. Nowell, III
	*Stephen S. Rasmussen
	*Oliver G. Richard, III
	*Sara Martinez Tucker

*By:	/s/ Brian X. Tierney		February 22, 2018
	(Brian X. Tierney, Attorney-in-Fact)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.



	AEP Texas Inc.
	Appalachian Power Company
	Ohio Power Company
	Public Service Company of Oklahoma
	Southwestern Electric Power Company

	By:	/s/ Brian X. Tierney
		(Brian X. Tierney, Vice President and Chief Financial Officer)

Date: February 22, 2018

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.



Signature		Title	Date

(i)	Principal Executive Officer:

	/s/ Nicholas K. Akins	Chairman of the Board, Chief Executive Officer and Director	February 22, 2018
	(Nicholas K. Akins)	Chairman of the Board, Chief Executive Officer and Director

(ii)	Principal Financial Officer:

	/s/ Brian X. Tierney	Vice President, Chief Financial Officer and Director	February 22, 2018
	(Brian X. Tierney)	Vice President, Chief Financial Officer and Director

(iii)	Principal Accounting Officer:

	/s/ Joseph M. Buonaiuto	Controller and Chief Accounting Officer	February 22, 2018
	(Joseph M. Buonaiuto)	Controller and Chief Accounting Officer

(iv)	A Majority of the Directors:

	*Nicholas K. Akins
	*Lisa M. Barton
	*Paul Chodak III
	*David M. Feinberg
	*Lana L. Hillebrand
	*Mark C. McCullough
	*Charles R. Patton
	Brian X. Tierney

*By:	/s/ Brian X. Tierney		February 22, 2018
	(Brian X. Tierney, Attorney-in-Fact)

SIGNATURES



	Indiana Michigan Power Company

	By:	/s/ Brian X. Tierney
		(Brian X. Tierney, Vice President
		and Chief Financial Officer)

Date: February 22, 2018



Signature		Title	Date

(i)	Principal Executive Officer:

	/s/ Nicholas K. Akins	Chairman of the Board, Chief Executive Officer and Director	February 22, 2018
	(Nicholas K. Akins)	Chairman of the Board, Chief Executive Officer and Director

(ii)	Principal Financial Officer:

	/s/ Brian X. Tierney	Vice President, Chief Financial Officer and Director	February 22, 2018
	(Brian X. Tierney)	Vice President, Chief Financial Officer and Director

(iii)	Principal Accounting Officer:

	/s/ Joseph M. Buonaiuto	Controller and Chief Accounting Officer	February 22, 2018
	(Joseph M. Buonaiuto)	Controller and Chief Accounting Officer

(iv)	A Majority of the Directors:

	*Nicholas K. Akins
	*Lisa M. Barton
	*Nicholas M. Elkins
	*Thomas A. Kratt
	*Marc E. Lewis
	*David A. Lucas
	*Mark C. McCullough
	*Carla E. Simpson
	*Toby L. Thomas
	Brian X. Tierney

*By:	/s/ Brian X. Tierney		February 22, 2018
	(Brian X. Tierney, Attorney-in-Fact)

SIGNATURES



	AEP Transmission Company, LLC

	By:	/s/ Brian X. Tierney
		(Brian X. Tierney, Vice President,
		Chief Financial Officer, and Manager)

Date: February 22, 2018



Signature		Title	Date

(i)	Principal Executive Officer:

	/s/ Nicholas K. Akins	Chairman of the Board, Chief Executive Officer and Manager	February 22, 2018
	(Nicholas K. Akins)	Chairman of the Board, Chief Executive Officer and Manager

(ii)	Principal Financial Officer:

	/s/ Brian X. Tierney	Vice President, Chief Financial Officer and Manager	February 22, 2018
	(Brian X. Tierney)	Vice President, Chief Financial Officer and Manager

(iii)	Principal Accounting Officer:

	/s/ Joseph M. Buonaiuto	Controller and Chief Accounting Officer	February 22, 2018
	(Joseph M. Buonaiuto)	Controller and Chief Accounting Officer

(iv)	A Majority of the Managers:

	*Nicholas K. Akins
	*Lisa M. Barton
	*David M. Feinberg
	*A. Wade Smith
	Brian X. Tierney

*By:	/s/ Brian X. Tierney		February 22, 2018
	(Brian X. Tierney, Attorney-in-Fact)

INDEX OF FINANCIAL STATEMENT SCHEDULES



	Page Number
Reports of Independent Registered Public Accounting Firm	S-2

The following financial statement schedules are included in this report on the pages indicated:

American Electric Power Company, Inc. (Parent):
Schedule I – Condensed Financial Information	S-4
Schedule I – Index of Condensed Notes to Condensed Financial Information	S-8

American Electric Power Company, Inc. and Subsidiary Companies:
Schedule II – Valuation and Qualifying Accounts and Reserves	S-11

S-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON

FINANCIAL STATEMENT SCHEDULES

To the Board of Directors and Shareholders of

American Electric Power Company, Inc.

Our audit of the consolidated financial statements referred to in our report dated February 22, 2018 appearing in the 2017 Annual Report to Shareholders of American Electric Power Company, Inc. (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the accompanying schedule of condensed financial information and the schedule of valuation and qualifying accounts and reserves as of December 31, 2017 and for the year then ended. In our opinion, these financial statement schedules as of December 31, 2017 and for the year then ended present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio

February 22, 2018

S-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

American Electric Power Company, Inc.:

We have audited the consolidated financial statements of American Electric Power Company, Inc. and subsidiary companies (the “Company”) as of December 31, 2016, and for each of the two years in the period ended December 31, 2016, and have issued our report thereon dated February 27, 2017; such consolidated financial statements and report is included in the Company’s 2017 Annual Report and are incorporated herein by reference. Our audit also included the financial statement schedules of the Company listed in Item 15. These financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 27, 2017

S-3

SCHEDULE I

AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED STATEMENTS OF INCOME

For the Years Ended December 31, 2017, 2016 and 2015

(in millions, except per-share and share amounts)



	Years Ended December 31,
	2017			2016			2015
REVENUES
Affiliated Revenues	$	9.1		$	9.7		$	10.7
Other Revenues	5.9			2.8			—
TOTAL REVENUES	15.0			12.5			10.7

EXPENSES
Other Operation	35.9			42.0			29.0
Depreciation	0.3			0.2			0.7
TOTAL EXPENSES	36.2			42.2			29.7

OPERATING LOSS	(21.2		)	(29.7		)	(19.0		)

Other Income (Expense):
Interest Income	20.5			11.3			5.9
Interest Expense	(43.1		)	(26.8		)	(19.1		)

LOSS BEFORE INCOME TAX CREDIT AND EQUITY EARNINGS	(43.8		)	(45.2		)	(32.2		)

Income Tax Expense (Credit)	0.1			(87.5		)	(1.5		)
Equity Earnings of Unconsolidated Subsidiaries	1,956.5			571.1			1,794.1

INCOME FROM CONTINUING OPERATIONS	1,912.6			613.4			1,763.4

INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF TAX	—			(2.5		)	283.7

NET INCOME	1,912.6			610.9			2,047.1

Other Comprehensive Income (Loss)	88.5			(29.2		)	(30.0		)

TOTAL COMPREHENSIVE INCOME	$	2,001.1		$	581.7		$	2,017.1

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	491,814,651			491,495,458			490,340,522

BASIC EARNINGS PER SHARE ATTRIBUTABLE TO COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS	$	3.89		$	1.25		$	3.59
BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS	—			(0.01		)	0.58
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	3.89		$	1.24		$	4.17

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	492,611,067			491,662,007			490,574,568

DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS	$	3.88		$	1.25		$	3.59
DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS	—			(0.01		)	0.58
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	3.88		$	1.24		$	4.17

See Condensed Notes to Condensed Financial Information beginning on page S-7.

S-4

SCHEDULE I

AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED BALANCE SHEETS

ASSETS

December 31, 2017 and 2016

(in millions)



	December 31,
	2017		2016
CURRENT ASSETS
Cash and Cash Equivalents	$	132.1	$	125.3
Other Temporary Investments	2.0		2.0
Advances to Affiliates	989.5		913.1
Accounts Receivable:
Affiliated Companies	2.5		3.0
General	7.6		58.6
Total Accounts Receivable	10.1		61.6
Accrued Tax Benefits	40.3		107.8
Prepayments and Other Current Assets	4.1		4.1
TOTAL CURRENT ASSETS	1,178.1		1,213.9

PROPERTY, PLANT AND EQUIPMENT
General	1.8		1.2
Total Property, Plant and Equipment	1.8		1.2
Accumulated Depreciation and Amortization	0.8		0.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	1.0		0.6

OTHER NONCURRENT ASSETS
Investments in Unconsolidated Subsidiaries	19,720.8		18,197.0
Affiliated Notes Receivable	50.0		20.0
Deferred Charges and Other Noncurrent Assets	70.0		106.6
TOTAL OTHER NONCURRENT ASSETS	19,840.8		18,323.6

TOTAL ASSETS	$	21,019.9	$	19,538.1

See Condensed Notes to Condensed Financial Information beginning on page S-7.

S-5

SCHEDULE I

AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED BALANCE SHEETS

LIABILITIES AND EQUITY

December 31, 2017 and 2016

(dollars in millions)



			December 31,
			2017			2016
CURRENT LIABILITIES
Advances from Affiliates			$	465.1		$	198.4
Accounts Payable:
General			4.0			2.5
Affiliated Companies			6.1			2.2
Short-term Debt			898.6			1,040.0
Long-term Debt Due Within One Year – Nonaffiliated			2.5			548.6
Other Current Liabilities			9.9			8.7
TOTAL CURRENT LIABILITIES			1,386.2			1,800.4

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			1,281.8			297.5
Deferred Credits and Other Noncurrent Liabilities			53.0			43.2
TOTAL NONCURRENT LIABILITIES			1,334.8			340.7

TOTAL LIABILITIES			2,721.0			2,141.1

MEZZANINE EQUITY
Contingently Redeemable Performance Share Awards			11.9			—

COMMON SHAREHOLDERS’ EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2017	2016
Shares Authorized	600,000,000	600,000,000
Shares Issued	512,210,644	512,048,520
(20,205,046 and 20,336,592 Shares were Held in Treasury as of December 31, 2017 and December 31, 2016, Respectively)			3,329.4			3,328.3
Paid-in Capital			6,398.7			6,332.6
Retained Earnings			8,626.7			7,892.4
Accumulated Other Comprehensive Income (Loss)			(67.8		)	(156.3		)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			18,287.0			17,397.0

TOTAL LIABILITIES, MEZZANINE EQUITY AND SHAREHOLDERS’ EQUITY			$	21,019.9		$	19,538.1

See Condensed Notes to Condensed Financial Information beginning on page S-7.

S-6

SCHEDULE I

AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2017, 2016 and 2015

(in millions)



	Years Ended December 31,
	2017			2016			2015
OPERATING ACTIVITIES
Net Income	$	1,912.6		$	610.9		$	2,047.1
Income (Loss) from Discontinued Operations	—			(2.5		)	283.7
Income from Continuing Operations	1,912.6			613.4			1,763.4
Adjustments to Reconcile Income from Continuing Operations to Net Cash
Flows from Continuing Operating Activities:
Depreciation and Amortization	0.3			0.2			0.7
Deferred Income Taxes	33.7			(54.1		)	(1.0		)
Equity Earnings of Unconsolidated Subsidiaries	(1,956.5		)	(571.1		)	(1,794.1		)
Cash Dividends Received from Unconsolidated Subsidiaries	827.0			859.1			984.5
Change in Other Noncurrent Assets	(0.4		)	(1.0		)	8.2
Change in Other Noncurrent Liabilities	74.0			13.8			14.1
Changes in Certain Components of Continuing Working Capital:
Accounts Receivable, Net	51.5			11.1			4.4
Accounts Payable	1.6			2.4			(0.6		)
Other Current Assets	70.0			(33.3		)	(0.7		)
Other Current Liabilities	0.7			(1.7		)	9.2
Net Cash Flows from Continuing Operating Activities	1,014.5			838.8			988.1

INVESTING ACTIVITIES
Construction Expenditures	(0.7		)	(0.4		)	(1.0		)
Change in Advances to Affiliates, Net	(76.4		)	(276.2		)	132.2
Capital Contributions to Unconsolidated Subsidiaries	(563.2		)	(310.2		)	(473.0		)
Return of Capital Contributions from Unconsolidated Subsidiaries	263.3			—			179.0
Issuance of Notes Receivable to Affiliated Companies	(30.0		)	—			—
Repayments of Notes Receivable from Affiliated Companies	—			—			25.0
Net Cash Flows Used for Continuing Investing Activities	(407.0		)	(586.8		)	(137.8		)

FINANCING ACTIVITIES
Issuance of Common Stock, Net	12.2			34.2			81.6
Issuance of Long-term Debt	992.3			—			—
Change in Short-term Debt, Net	(141.4		)	915.0			(477.0		)
Retirement of Long-term Debt	(550.0		)	—			—
Change in Advances from Affiliates, Net	266.7			(46.2		)	128.7
Dividends Paid on Common Stock	(1,175.4		)	(1,115.7		)	(1,054.2		)
Other Financing Activities	(5.1		)	(4.8		)	(7.4		)
Net Cash Flows Used for Continuing Financing Activities	(600.7		)	(217.5		)	(1,328.3		)

Net Cash Flows from (Used for) Discontinued Operating Activities	—			(2.5		)	24.6
Net Cash Flows from Discontinued Investing Activities	—			—			483.5
Net Cash Flows from Discontinued Financing Activities	—			—			—

Net Increase in Cash and Cash Equivalents	6.8			32.0			30.1
Cash and Cash Equivalents at Beginning of Period	125.3			93.3			63.2
Cash and Cash Equivalents at End of Period	$	132.1		$	125.3		$	93.3

See Condensed Notes to Condensed Financial Information beginning on page S-7.

S-7

SCHEDULE I

AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL INFORMATION

1. Summary of Significant Accounting Policies

2. Commitments, Guarantees and Contingencies

3. Financing Activities

4. Related Party Transactions

S-8

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The condensed financial information of Parent is required as a result of the restricted net assets of AEP consolidated subsidiaries exceeding 25% of AEP consolidated net assets as of December 31, 2017. Parent is a public utility holding company that owns all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries, including joint ventures and equity investments. The primary source of income for Parent is equity in its subsidiaries’ earnings. Its major source of cash is dividends from the subsidiaries. Parent borrows the funds for the money pool that is used by the subsidiaries for their short-term cash needs.

Income Taxes

Parent files a consolidated federal income tax return with its subsidiaries. AEP System’s current consolidated federal income tax is allocated to AEP System companies so that their current tax expense reflects a separate return result for each company in the consolidated group. The tax benefit of Parent is allocated to its subsidiaries with taxable income.

2. COMMITMENTS, GUARANTEES AND CONTINGENCIES

Parent and its subsidiaries are parties to environmental and other legal matters. For further discussion of commitments, guarantees and contingencies, see Note 6 in the 2017 Annual Reports.

3. FINANCING ACTIVITIES

The following details long-term debt outstanding as of December 31, 2017 and 2016:

Long-term Debt



	Weighted Average	Interest Rate Ranges as of		Outstanding as of
	Interest Rate as of	December 31,		December 31,
Type of Debt and Maturity	December 31, 2017	2017	2016	2017		2016
				(in millions)
Senior Unsecured Notes
2017-2027	2.74%	2.15% - 3.20%	1.65% - 2.95%	$	1,284.3	$	846.1
Total Long-term Debt Outstanding				1,284.3		846.1
Long-term Debt Due Within One Year				2.5		548.6
Long-term Debt				$	1,281.8	$	297.5

Long-term debt outstanding as of December 31, 2017 is payable as follows:



	2018		2019		2020		2021			2022		After 2022		Total
	(in millions)
Principal Amount	$	2.5	$	0.4	$	499.7	$	(0.5	)	$	299.5	$	492.1	$	1,293.7
Unamortized Discount, Net and Debt Issuance Costs														(9.4		)
Total Long-term Debt Outstanding														$	1,284.3

S-9

Short-term Debt

Parent’s outstanding short-term debt was as follows:



	December 31,
	2017				2016
Type of Debt	Outstanding Amount		Weighted Average Interest Rate		Outstanding Amount		Weighted Average Interest Rate
	(in millions)				(in millions)
Commercial Paper	$	898.6	1.85	%	$	1,040.0	1.02	%
Total Short-term Debt	$	898.6			$	1,040.0

4. RELATED PARTY TRANSACTIONS

Payments on Behalf of Subsidiaries

Due to occasional time sensitivity and complexity of payments, Parent makes certain insurance, tax and benefit payments on behalf of subsidiary companies. Parent is then fully reimbursed by the subsidiary companies.

Short-term Lending to Subsidiaries

Parent uses a commercial paper program to meet the short-term borrowing needs of subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. The program also allows some direct borrowers to invest excess cash with Parent.

Interest expense related to Parent’s short-term borrowing is included in Interest Expense on Parent’s statements of income. Parent incurred interest expense for amounts borrowed from subsidiaries of $8 million, $2 million and $2 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Interest income related to Parent’s short-term lending is included in Interest Income on Parent’s statements of income. Parent earned interest income for amounts advanced to subsidiaries of $16 million, $10 million and $4 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Global Borrowing Notes

Parent issued long-term debt, portions of which were loaned to its subsidiaries. Parent pays interest on the global notes, but the subsidiaries accrue interest for their share of the global borrowing and remit the interest to Parent. Interest income related to Parent’s loans to subsidiaries is included in Interest Income on Parent’s statements of income. Parent earned interest income on loans to subsidiaries of $2 million, $1 million and $1 million for the years ended December 31, 2017, 2016 and 2015, respectively.

S-10

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES



AEP			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts (a)		Deductions (b)		Balance at End of Period
	(in millions)
Deducted from Assets:
Accumulated Provision for Uncollectible
Accounts:
Year Ended December 31, 2017	$	37.9	$	34.0	$	2.5	$	35.9	$	38.5
Year Ended December 31, 2016	29.0		40.7		2.6		34.4		37.9
Year Ended December 31, 2015	20.8		51.9		2.7		46.4		29.0


(a)	Recoveries offset by reclasses to other assets and liabilities.


(b)	Uncollectible accounts written off.

Schedule II for the Registrant Subsidiaries is not presented because the amounts are not material.

S-11

INDEX OF AEP TRANSMISSION COMPANY, LLC (AEPTCO PARENT)

FINANCIAL STATEMENT SCHEDULES



	Page Number
Report of Independent Registered Public Accounting Firm	S-13

The following financial statement schedules are included in this report on the pages indicated:

AEP Transmission Company, LLC (AEPTCo Parent):
Schedule I – Condensed Financial Information	S-14
Schedule I – Index of Condensed Notes to Condensed Financial Information	S-18

S-12

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON

FINANCIAL STATEMENT SCHEDULE

To the Board of Directors and Member of

AEP Transmission Company, LLC

Our audit of the consolidated financial statements referred to in our report dated February 22, 2018 appearing in the 2017 Annual Report to the Member of AEP Transmission Company, LLC (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the accompanying schedule of condensed financial information as of December 31, 2017 and for the year then ended. In our opinion, this financial statement schedule as of December 31, 2017 and for the year then ended presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

The financial statement schedule of the Company as of December 31, 2016 and for the years ended December 31, 2016 and 2015 was audited by other auditors whose report, dated April 4, 2017, expressed an unqualified opinion on that financial statement schedule.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio

February 22, 2018

S-13

SCHEDULE I

AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED STATEMENTS OF INCOME

For the Years Ended December 31, 2017, 2016 and 2015

(in millions)



	Years Ended December 31,
	2017			2016			2015
EXPENSES
Other Operation	$	—		$	0.8		$	0.2
TOTAL EXPENSES	—			0.8			0.2

OPERATING LOSS	—			(0.8		)	(0.2		)

Other Income (Expense):
Interest Income − Affiliated	82.9			57.8			49.6
Interest Expense	(82.4		)	(57.9		)	(49.8		)

INCOME (LOSS) BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS	0.5			(0.9		)	(0.4		)

Income Tax Expense (Credit)	0.2			(0.3		)	(0.1		)
Equity Earnings of Unconsolidated Subsidiaries	285.8			193.3			133.2

NET INCOME	$	286.1		$	192.7		$	132.9

See Condensed Notes to Condensed Financial Information beginning on page S-18.

S-14

SCHEDULE I

AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED BALANCE SHEETS

ASSETS

December 31, 2017 and 2016

(in millions)



	December 31,
	2017		2016
CURRENT ASSETS
Advances to Affiliates	$	22.5	$	14.2
Accounts Receivable:
General	—		0.1
Affiliated Companies	17.3		21.7
Total Accounts Receivable	17.3		21.8
TOTAL CURRENT ASSETS	39.8		36.0

OTHER NONCURRENT ASSETS
Notes Receivable − Affiliated	2,550.4		1,932.0
Investments in Unconsolidated Subsidiaries	2,607.4		1,960.1
Deferred Charges and Other Noncurrent Assets	—		1.7
TOTAL OTHER NONCURRENT ASSETS	5,157.8		3,893.8

TOTAL ASSETS	$	5,197.6	$	3,929.8

See Condensed Notes to Condensed Financial Information beginning on page S-18.

S-15

SCHEDULE I

AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED BALANCE SHEETS

LIABILITIES AND EQUITY

December 31, 2017 and 2016

(in millions)



	December 31,
	2017		2016
CURRENT LIABILITIES
Accounts Payable:
General	$	0.4	$	0.1
Affiliated Companies	24.0		18.9
Long-term Debt Due Within One Year – Nonaffiliated	50.0		—
Accrued Taxes	0.1		—
Accrued Interest	15.0		10.5
Other Current Liabilities	2.5		10.7
TOTAL CURRENT LIABILITIES	92.0		40.2

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,500.4		1,932.0
TOTAL NONCURRENT LIABILITIES	2,500.4		1,932.0

TOTAL LIABILITIES	2,592.4		1,972.2

MEMBER’S EQUITY
Paid-in Capital	1,816.5		1,455.0
Retained Earnings	788.7		502.6
TOTAL MEMBER’S EQUITY	2,605.2		1,957.6

TOTAL LIABILITIES AND MEMBER’S EQUITY	$	5,197.6	$	3,929.8

See Condensed Notes to Condensed Financial Information beginning on page S-18.

S-16

SCHEDULE I

AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2017, 2016 and 2015

(in millions)



	Years Ended December 31,
	2017			2016			2015
OPERATING ACTIVITIES
Net Income	$	286.1		$	192.7		$	132.9
Adjustments to Reconcile Net Income to Net Cash Flows
from Operating Activities:
Deferred Income Taxes	1.6			(1.7		)	—
Equity Earnings of Unconsolidated Subsidiaries	(285.7		)	(193.3		)	(133.1		)
Change in Other Noncurrent Assets	—			0.2			—
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	4.5			2.2			(13.0		)
Accounts Payable	5.4			2.8			1.4
Accrued Taxes, Net	0.1			0.1			(0.1		)
Accrued Interest	4.5			2.6			0.9
Other Current Liabilities	(8.2		)	(5.5		)	12.2
Net Cash Flows from Operating Activities	8.3			0.1			1.2

INVESTING ACTIVITIES
Change in Advances to Affiliates, Net	(8.3		)	(0.1		)	(1.2		)
Issuance of Notes Receivable to Affiliated Companies	(617.6		)	(686.9		)	(450.0		)
Repayments of Notes Receivable from Affiliated Companies	—			300.0			—
Capital Contributions to Subsidiaries	(361.6		)	(212.0		)	(279.0		)
Net Cash Flows Used for Investing Activities	(987.5		)	(599.0		)	(730.2		)

FINANCING ACTIVITIES
Capital Contribution from Member	361.6			212.0			279.0
Issuance of Long-term Debt - Nonaffiliated	617.6			686.9			450.0
Retirement of Long-term Debt - Nonaffiliated	—			(300.0		)	—
Net Cash Flows from Financing Activities	979.2			598.9			729.0

Net Change in Cash and Cash Equivalents	—			—			—
Cash and Cash Equivalents at Beginning of Period	—			—			—
Cash and Cash Equivalents at End of Period	$	—		$	—		$	—

See Condensed Notes to Condensed Financial Information beginning on page S-18.

S-17

SCHEDULE I

AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL INFORMATION

1. Summary of Significant Accounting Policies

2. Commitments, Guarantees and Contingencies

3. Financing Activities

4. Related Party Transactions

S-18

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The condensed financial information of AEPTCo Parent is required as a result of the restricted net assets of AEPTCo consolidated subsidiaries exceeding 25% of AEPTCo consolidated net assets as of December 31, 2017. AEPTCo Parent is the direct holding company for the seven State Transcos. The primary source of income for AEPTCo Parent is equity in its subsidiaries’ earnings.

Income Taxes

AEPTCo Parent joins in the filing of a consolidated federal income tax return with its affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of AEP Parent is allocated to its subsidiaries with taxable income.

2. COMMITMENTS, GUARANTEES AND CONTINGENCIES

AEPTCo Parent and its subsidiaries are parties to legal matters. For further discussion of commitments, guarantees and contingencies, see Note 6 in the 2017 Annual Reports.

3. FINANCING ACTIVITIES

For discussion of Financing Activities, see Note 14 to AEPTCo’s audited consolidated financial statements in the 2017 Annual Reports.

4. RELATED PARTY TRANSACTIONS

Payments on Behalf of Subsidiaries

Due to occasional time sensitivity and complexity of payments, Parent makes certain insurance, tax and other payments on behalf of subsidiary companies. Parent is then fully reimbursed by the subsidiary companies. AEPTCo Parent also makes convenience payments on behalf of its State Transcos. AEPTCo Parent is then fully reimbursed by its State Transcos.

Long-term Lending to Subsidiaries

AEPTCo Parent enters into debt arrangements with nonaffiliated entities. AEPTCo Parent has Long-term Debt of $2.6 billion and $1.9 billion as of December 31, 2017 and 2016, respectively. AEPTCo Parent uses the proceeds from these nonaffiliated debt arrangements to make affiliated loans to its State Transcos using the same interest rates and maturity dates as the nonaffiliated debt arrangements. AEPTCo Parent has recorded Notes Receivable − Affiliated of $2.6 billion and $1.9 billion as of December 31, 2017 and 2016, respectively. Related to these nonaffiliated and affiliated debt arrangements, AEPTCo Parent has recorded Accrued Interest and Accounts Receivable − Affiliated Companies of $15 million and $11 million as of December 31, 2017 and 2016, respectively. AEPTCo Parent has recorded Interest Income − Affiliated of $82 million, $57 million and $50 million for the years ended December 31, 2017, 2016 and 2015, respectively, related to the Notes Receivable − Affiliated. AEPTCo Parent has recorded Interest Expense of $82 million, $58 million and $50 million for the years ended December 31, 2017, 2016 and 2015, respectively, related to the nonaffiliated debt arrangements.

S-19

Short-term Lending to Subsidiaries

Interest expense related to AEPTCo Parent’s short-term borrowing is included in Interest Expense on AEPTCo Parent’s statements of income. AEPTCo Parent incurred immaterial interest expense for amounts borrowed from AEP affiliates for the years ended December 31, 2017, 2016 and 2015.

Interest income related to AEPTCo Parent’s short-term lending is included in Interest Income − Affiliated on AEPTCo Parent’s statements of income. AEPTCo Parent earned interest income for amounts advanced to AEP affiliates of $1 million for the year ended December 31, 2017. The amounts for the years ended December 31, 2016 and 2015 were immaterial.

S-20

EXHIBIT INDEX

The documents listed below are being filed or have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof. Exhibits (“Ex”) not identified as previously filed are filed herewith. Exhibits designated with a dagger (†) are management contracts or compensatory plans or arrangements required to be filed as an Exhibit to this Form. Exhibits designated with an asterisk (*) are filed herewith.



Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:

AEP‡ File No. 1-3525

3(a)	Composite of the Restated Certificate of Incorporation of AEP, dated April 23, 2015.	Form 10-Q, Ex 3, June 30, 2015

3(b)	Composite By-Laws of AEP, as amended as of October 20, 2015.	Form 8-K, Ex 3(b) dated October 21, 2015

4(a)	Indenture (for unsecured debt securities), dated as of May 1, 2001, between AEP and The Bank of New York, as Trustee.	Registration Statement No. 333-86050, Ex 4(a)(b)(c) Registration Statement No. 333-105532, Ex 4(d)(e)(f) Registration Statement No. 333-200956, Ex 4(b)

4(a)1	Company Order and Officers Certificate to The Bank of New York Mellon Trust Company, N.A. dated November 13, 2017 of 2.15% Senior Notes Series G due 2020 and 3.20% Senior Notes, Series H due 2027.	Form 8-K, Ex 4(a) dated November 13, 2017

4(b)	$3,000,000,000 Fourth Amended and Restated Credit Agreement dated June 30, 2016 among AEP, the banks, financial institutions and other institutional lenders listed on the signature pages thereof and Wells Fargo Bank, N.A., as Administrative Agent.	Form 10-Q, Ex 4(c), June 30, 2016

10(a)	Lease Agreements, dated as of December 1, 1989, between AEGCo or I&M and Wilmington Trust Company, as amended.	Registration Statement No. 33-32752, Ex 28(c)(1-6)(C) Registration Statement No. 33-32753, Ex 28(a)(1-6)(C) AEGCo 1993 Form 10-K, Ex 10(c)(1-6)(B) I&M 1993 Form 10-K, Ex 10(e)(1-6)(B)

10(b)	Consent Decree with U.S. District Court dated October 9, 2007, as modified.	Form 8-K, Ex 10.1 dated October 9, 2007 Form 10-Q, Ex 10, June 30, 2013

10(c)	Purchase and Sale Agreement by and among AEP Generation Resources Inc., AEP Generating Company and Burgundy Power LLC dated as of September 13, 2016.	Form 10-Q, Ex 10(b), September 30, 2016

†10(d)	AEP Accident Coverage Insurance Plan for Directors.	1985 Form 10-K, Ex 10(g)

†10(e)	AEP Retainer Deferral Plan for Non-Employee Directors, as Amended and Restated effective July 26, 2016.	2016 Form 10-K, Ex 10(h)

†10(f)	AEP Stock Unit Accumulation Plan for Non-Employee Directors as amended July 26, 2016.	2016 Form 10-K, Ex 10(i)

†10(g)	AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2008.	2008 Form 10-K, Ex 10(l)(1)(A)

†10(g)(1)	Guaranty by AEP of AEPSC Excess Benefits Plan.	1990 Form 10-K, Ex 10(h)(1)(B)

†10(h)	AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2011 (Non-Qualified).	2010 Form 10-K, Ex 10

E-1



Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:

†10(h)(1)(A)	Amendment to AEP System Supplemental Retirement Savings Plan, as Amended and Restated as of January 1, 2011 (Non-Qualified).	2014 Form 10-K, Ex 10(l)(1)(A)

†10(i)	AEPSC Umbrella Trust for Executives.	1993 Form 10-K, Ex 10(g)(3)

†10(i)(1)(A)	First Amendment to AEPSC Umbrella Trust for Executives.	2008 Form 10-K, Ex 10(l)(3)(A)

*10(j)	AEP System Senior Officer Annual Incentive Compensation Plan amended and restated as of February 20, 2017.

†10(k)	AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008.	2008 Form 10-K, Ex 10(p)

†10(k)(1)(A)	First Amendment to AEP System Incentive Compensation Deferral Plan, as Amended and Restated effective January 1, 2008.	2011 Form 10-K, Ex 10(p)(1)(A)

†10(k)(2)(A)	Second Amendment to AEP System Incentive Compensation Deferral Plan, as Amended and Restated effective January 1, 2008.	2014 Form 10-K, Ex 10(q)(2)(A)

†10(l)	AEP Change In Control Agreement, as Revised Effective January 1, 2017.	Form 10-Q, Ex 10(c) , September 30, 2016

†10(m)	Amended and Restated AEP System Long-Term Incentive Plan as of September 21, 2016.	Form 10-Q, Ex 10(a) , September 30, 2016

†10(m)(1)(A)	Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.	Form 10-Q, Ex 10(a), March 30, 2017

†10(m)(2)(A)	Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan as Amended and Restated.	Form 10-Q, Ex 10(b), March 30, 2017

†10(n)	AEP System Stock Ownership Requirement Plan Amended and Restated effective June 20, 2017.	Form 10-Q, Ex 10, June 30, 2017

†10(o)	Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2009.	2008 Form 10-K, Ex 10(v)

†10(p)	AEP Executive Severance Plan Amended and Restated effective October 24, 2016.	Form 10-Q, Ex 10(d) , September 30, 2016

†10(q)	Letter Agreement dated November 20, 2012 between AEPSC and Lana Hillebrand.	2013 Form 10-K, Ex 10(x)

*12	Statement re: Computation of Ratios.

*13	Copy of those portions of the AEP 2017 Annual Report (for the fiscal year ended December 31, 2017) which are incorporated by reference in this filing.

*21	List of subsidiaries of AEP.

*23 (1)	Consent of PricewaterhouseCoopers LLP.

*23 (2)	Consent of Deloitte & Touche LLP.

*24	Power of Attorney.

E-2



Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:

*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

101.INS	XBRL Instance Document.

101.SCH	XBRL Taxonomy Extension Schema.

101.CAL	XBRL Taxonomy Extension Calculation Linkbase.

101.DEF	XBRL Taxonomy Extension Definition Linkbase.

101.LAB	XBRL Taxonomy Extension Label Linkbase.

101.PRE	XBRL Taxonomy Extension Presentation Linkbase.

AEP TEXAS‡ File No. 333-221643

3(a)	Composite of the Restated Certificate of Incorporation, as amended.	Registration No. 333-221643, Ex 3(a)

3(b)	Bylaws.	Registration No. 333-221643, Ex 3(b)

4(a)(1)	Indenture, dated as of September 1, 2017, between AEP Texas Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee.	Registration No. 333-221643, Ex 4(a)-1

4(a)(2)	First Supplemental Indenture dated as of September 22, 2017, between AEP Texas Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee.	Registration No. 333-221643, Ex 4(a)-2

*4(a)(3)	Company Order and Officers’ Certificate to The Bank of New York Mellon Trust Company, N.A. dated January 11, 2018 of 2.40% Senior Notes, Series C due 2022 and 3.80% Senior Notes, Series D due 2047.

*12	Statement re: Computation of Ratios.

*13	Copy of those portions of the AEP Texas 2017 Annual Report (for the fiscal year ended December 31, 2017) which are incorporated by reference in this filing.

*24	Power of Attorney.

*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

E-3



Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:

*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

101.INS	XBRL Instance Document.

101.SCH	XBRL Taxonomy Extension Schema.

101.CAL	XBRL Taxonomy Extension Calculation Linkbase.

101.DEF	XBRL Taxonomy Extension Definition Linkbase.

101.LAB	XBRL Taxonomy Extension Label Linkbase.

101.PRE	XBRL Taxonomy Extension Presentation Linkbase.

AEPTCo‡ File No. 333-217143

3(a)	Limited Liability Company Agreement of AEP Transmission Company, LLC dated as of January 27, 2006.	Registration Statement No. 333-217143, Ex 3(a)

3(b)	First Amendment to Limited Liability Company Agreement dated as of May 21, 2013.	Registration Statement No. 333-217143, Ex 3(b)

4(a)(1)	Indenture, dated as of November 1, 2016, between AEP Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A., as Trustee.	Registration Statement No. 333-217143, Ex 4(a)-1

4(a)(2)	First Supplemental Indenture dated as of November 21, 2016, between AEP Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A., as Trustee.	Registration Statement No. 333-217143, Ex 4(a)-2

4(a)(3)	Second Supplemental Indenture dated as of September 28, 2017.	Form 8-K, Ex 4(b) dated September 28, 2017

*4(a)(4)	Company Order and Officers’ Certificate to The Bank of New York Mellon Trust Company, N.A. dated May 24, 2017 of 3.10% Senior Notes, Series F due 2026 and 4.00% Senior Notes, Series G due 2046.

*4(a)(5)	Company Order and Officers’ Certificate to The Bank of New York Mellon Trust Company, N.A. dated September 28, 2017 of 3.10% Senior Notes, Series D due 2026.

*4(a)(6)	Company Order and Officers’ Certificate to The Bank of New York Mellon Trust Company, N.A. dated September 28, 2017 of 3.75% Senior Notes, Series H due 2047.

*4(b)	Registration Rights Agreement, dated September 28, 2017.

4(c)(1)	Note Purchase Agreement, dated as of October 18, 2012 between AEP Transmission Company, LLC and the Initial Purchasers.	Registration Statement No. 333-217143, Ex 4(c)-1

4(c)(2)	Supplement to Note Purchase Agreement, dated as of November 7, 2013 between AEP Transmission Company, LLC and the Initial Purchasers.	Registration Statement No. 333-217143, Ex 4(c)-2

E-4



Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:

4(c)(3)	Supplement to Note Purchase Agreement, dated as of November 14, 2014 between AEP Transmission Company, LLC and the Initial Purchasers.	Registration Statement No. 333-217143, Ex 4(c)-3

*12	Statement re: Computation of Ratios.

*13	Copy of those portions of the AEPTCo 2017 Annual Report (for the fiscal year ended December 31, 2017) which are incorporated by reference in this filing.

*24	Power of Attorney.

*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

101.INS	XBRL Instance Document.

101.SCH	XBRL Taxonomy Extension Schema.

101.CAL	XBRL Taxonomy Extension Calculation Linkbase.

101.DEF	XBRL Taxonomy Extension Definition Linkbase.

101.LAB	XBRL Taxonomy Extension Label Linkbase.

101.PRE	XBRL Taxonomy Extension Presentation Linkbase.

APCo‡ File No. 1-3457

3(a)	Composite of the Restated Articles of Incorporation of APCo, amended as of March 7, 1997.	1996 Form 10-K, Ex 3(d)

3(b)	Composite By-Laws of APCo, amended as of February 26, 2008.	2007 Form 10-K, Ex 3(b)

4(a)	Indenture (for unsecured debt securities), dated as of January 1, 1998, between APCo and The Bank of New York, As Trustee.	Registration Statement No. 333-45927, Ex 4(a)(b) Registration Statement No. 333-49071, Ex 4(b) Registration Statement No. 333-84061, Ex 4(b)(c) Registration Statement No. 333-100451, Ex 4(b) Registration Statement No. 333-116284, Ex 4(b)(c) Registration Statement No. 333-123348, Ex 4(b)(c) Registration Statement No. 333-136432, Ex 4(b)(c)(d) Registration Statement No. 333-161940, Ex 4(b)(c)(d) Registration Statement No. 333-182336, Ex 4(b)(c) Registration Statement No. 333-200750, Ex. 4(b)(c) Registration Statement No. 333-214448, Ex. 4(b)

4(a)(1)	Company Order and Officers Certificate to The Bank of New York Mellon Trust Company, N.A. dated May 11, 2017 of 3.30% Senior Notes Series X due 2027.	Form 8-K, Ex 4(a) dated May 11, 2017

10(a)	Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.	2013 Form 10-K, Ex 10(a)

E-5



Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:


10(d)	Consent Decree with U.S. District Court, as modified.	Form 8-K, Ex 10.1 dated October 9, 2007 Form 10-Q, Ex 10, June 30, 2013

*12	Statement re: Computation of Ratios.

*13	Copy of those portions of the APCo 2017 Annual Report (for the fiscal year ended December 31, 2017) which are incorporated by reference in this filing.

*23 (1)	Consent of PricewaterhouseCoopers LLP.

*23 (2)	Consent of Deloitte & Touche LLP.

*24	Power of Attorney.

*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

101.INS	XBRL Instance Document.

101.SCH	XBRL Taxonomy Extension Schema.

101.CAL	XBRL Taxonomy Extension Calculation Linkbase.

101.DEF	XBRL Taxonomy Extension Definition Linkbase.

101.LAB	XBRL Taxonomy Extension Label Linkbase.

101.PRE	XBRL Taxonomy Extension Presentation Linkbase.

I&M‡ File No. 1-3570

3(a)	Composite of the Amended Articles of Acceptance of I&M, dated of March 7, 1997.	1996 Form 10-K, Ex 3(c)

3(b)	Composite By-Laws of I&M, amended as of February 26, 2008.	2007 Form 10-K, Ex 3(b)

4(a)	Indenture (for unsecured debt securities), dated as of October 1, 1998, between I&M and The Bank of New York, as Trustee.	Registration Statement No. 333-88523, Ex 4(a)(b)(c) Registration Statement No. 333-58656, Ex 4(b)(c) Registration Statement No. 333-108975, Ex 4(b)(c)(d) Registration Statement No. 333-136538, Ex 4(b)(c) Registration Statement No. 333-156182, Ex 4(b) Registration Statement No. 333-185087, Ex 4(b) Registration Statement No. 333-207836, Ex 4(b)

4 (b)	Company Order and Officers Certificate to The Bank of New York Mellon Trust Company, N.A. dated March 3, 2016 of 4.55% Series K due 2046.	Form 8-K, Ex 4(a) dated March 3, 2016

4(c)	Company Order and Officers Certificate to The Bank of New York Mellon Trust Company, N.A. dated June 29, 2017 of 3.75% Series L due 2047.	Form 8-K, Ex 4(a) dated June 29, 2017

E-6



Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:

10(a)	Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.	2013 Form 10-K, Ex 10(a)

10(b)	Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended.	Registration Statement No. 33-32752, Ex 28(b)(1)(A)(B)

10(c)	Consent Decree with U.S. District Court, as modified.	Form 8-K, Ex 10.1 dated October 9, 2007 Form 10-Q, Ex 10, June 30, 2013

10(d)	Lease Agreements, dated as of December 1, 1989, between I&M and Wilmington Trust Company, as amended.	Registration Statement No. 33-32753, Ex 28(a)(1-6)(C) 1993 Form 10-K, Ex 10(e)(1-6)(B)

*12	Statement re: Computation of Ratios.

*13	Copy of those portions of the I&M 2017 Annual Report (for the fiscal year ended December 31, 2017) which are incorporated by reference in this filing.

*23 (1)	Consent of PricewaterhouseCoopers LLP.

*23 (2)	Consent of Deloitte & Touche LLP.

*24	Power of Attorney.

*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

101.INS	XBRL Instance Document.

101.SCH	XBRL Taxonomy Extension Schema.

101.CAL	XBRL Taxonomy Extension Calculation Linkbase.

101.DEF	XBRL Taxonomy Extension Definition Linkbase.

101.LAB	XBRL Taxonomy Extension Label Linkbase.

101.PRE	XBRL Taxonomy Extension Presentation Linkbase.

OPCo‡ File No.1-6543

3(a)	Composite of the Amended Articles of Incorporation of OPCo, dated June 3, 2002.	Form 10-Q, Ex 3(e), June 30, 2002

3(b)	Amended Code of Regulations of OPCo.	Form 10-Q, Ex 3(b), June 30, 2008

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Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:

4(a)	Indenture (for unsecured debt securities), dated as of September 1, 1997, between OPCo and Bankers Trust Company (now Deutsche Bank Trust Company Americas), as Trustee.	Registration Statement No. 333-49595, Ex 4(a)(b)(c) Registration Statement No. 333-106242, Ex 4(b)(c)(d) Registration Statement No. 333-127913, Ex 4(b)(c) Registration Statement No. 333-139802, Ex 4(b)(c)(d) Registration Statement No. 333-161537, Ex 4(b)(c)(d) Registration Statement No. 333-211192, Ex 4(b)

4(c)	Indenture (for unsecured debt securities), dated as of February 1, 2003, between OPCo and Bank One, N.A., as Trustee.	Registration Statement No. 333-127913, Ex 4(d)(e)(f)

4(d)	Indenture (for unsecured debt securities), dated as of September 1, 1997, between CSPCo (predecessor in interest to OPCo) and Bankers Trust Company, as Trustee.	Registration Statement No. 333-54025, Ex 4(a)(b)(c)(d) Registration Statement No. 333-128174, Ex 4(b)(c)(d) Registration Statement No. 333-150603, Ex 4(b)

4(e)	Indenture (for unsecured debt securities), dated as of February 1, 2003, between CSPCo (predecessor in interest to OPCo) and Bank One, N.A., as Trustee.	Registration Statement No. 333-128174, Ex 4(e)(f)(g) Registration Statement No. 333-150603, Ex 4(b)

4(f)	First Supplemental Indenture, dated as of December 31, 2011, by and between OPCo and Deutsche Bank Trust Company Americas, as trustee, supplementing the Indenture dated as of September 1, 1997 between CSPCo (predecessor in interest to OPCo) and the trustee.	Form 8-K, Ex 4.1 dated January 6, 2012

4(g)	Third Supplemental Indenture, dated as of December 31, 2011, by and between OPCo and The Bank of New York Mellon Trust Company, N.A., as trustee, supplementing the Indenture dated as of February 14, 2003 between CSPCo (predecessor in interest to OPCo) and the trustee.	Form 8-K, Ex 4.2 dated January 6, 2012

4(h)	CSPCo (predecessor in interest to OPCo) Company Order and Officer’s Certificate to Deutsche Bank Trust Company Americas, dated May 16, 2008, establishing terms of 6.05% Senior Notes, Series G, due 2018.	Form 8-K, Ex 4(a), dated May 16, 2008

10(a)	Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.	2013 Form 10-K, Ex 10(a)

10(b)	Consent Decree with U.S. District Court, as modified.	Form 8-K, Item Ex 10.1 dated October 9, 2007 Form 10-Q, Ex 10, June 30, 2013

*12	Statement re: Computation of Ratios.

*13	Copy of those portions of the OPCo 2017 Annual Report (for the fiscal year ended December 31, 2017) which are incorporated by reference in this filing.

*23 (1)	Consent of PricewaterhouseCoopers LLP.

*23 (2)	Consent of Deloitte & Touche LLP.

*24	Power of Attorney.

*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:


*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

101.INS	XBRL Instance Document.

101.SCH	XBRL Taxonomy Extension Schema.

101.CAL	XBRL Taxonomy Extension Calculation Linkbase.

101.DEF	XBRL Taxonomy Extension Definition Linkbase.

101.LAB	XBRL Taxonomy Extension Label Linkbase.

101.PRE	XBRL Taxonomy Extension Presentation Linkbase.

PSO‡ File No. 0-343

3(a)	Certificate of Amendment to Restated Certificate of Incorporation of PSO.	Form 10-Q, Ex 3(a), June 30, 2008

3(b)	Composite By-Laws of PSO amended as of February 26, 2008.	2007 Form 10-K, Ex 3 (b)

4(a)	Indenture (for unsecured debt securities), dated as of November 1, 2000, between PSO and The Bank of New York, as Trustee.	Registration Statement No. 333-100623, Ex 4(a)(b) Registration Statement No. 333-114665, Ex 4(b)(c) Registration Statement No. 333-133548, Ex 4(b)(c) Registration Statement No. 333-156319, Ex 4(b)(c)

4(b)	Eighth Supplemental Indenture, dated as of November 13, 2009 between PSO and The Bank of New York Mellon, as Trustee, establishing terms of the 5.15% Senior Notes, Series H, due 2019.	Form 8-K, Ex 4(a), dated November 13, 2009

4(c)	Ninth Supplemental Indenture, dated as of January 19, 2011 between PSO and The Bank of New York Mellon Trust Company, N.A., as Trustee, establishing terms of 4.40% Senior Notes, Series I, due 2021.	Form 8-K, Ex 4(a) dated January 20, 2011

*12	Statement re: Computation of Ratios.

*13	Copy of those portions of the PSO 2017 Annual Report (for the fiscal year ended December 31, 2017) which are incorporated by reference in this filing.

*24	Power of Attorney.

*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

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Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:


101.INS	XBRL Instance Document.

101.SCH	XBRL Taxonomy Extension Schema.

101.CAL	XBRL Taxonomy Extension Calculation Linkbase.

101.DEF	XBRL Taxonomy Extension Definition Linkbase.

101.LAB	XBRL Taxonomy Extension Label Linkbase.

101.PRE	XBRL Taxonomy Extension Presentation Linkbase.

SWEPCo‡ File No. 1-3146

3(a)	Composite of Amended Restated Certificate of Incorporation of SWEPCo.	2008 Form 10-K, Ex 3(a)

3(b)	Composite By-Laws of SWEPCo amended as of February 26, 2008.	2007 Form 10-K, Ex 3(b)

4(a)	Indenture (for unsecured debt securities), dated as of February 4, 2000, between SWEPCo and The Bank of New York, as Trustee.	Registration Statement No. 333-96213 Registration Statement No. 333-87834, Ex 4(a)(b) Registration Statement No. 333-100632, Ex 4(b) Registration Statement No. 333-108045, Ex 4(b) Registration Statement No. 333-145669, Ex 4(c)(d) Registration Statement No. 333-161539, Ex 4(b)(c) Registration Statement No. 333-194991, Ex 4(b)(c) Registration Statement No. 333-208535, Ex 4(b)(c)

4(b)	Eleventh Supplemental Indenture, dated as of September 26, 2016 between SWEPCo and The Bank of New York Mellon Trust Company, N.A., as Trustee, establishing terms of the 2.75% Senior Notes, Series K, due 2026.	Form 8-K, Ex 4(a) dated September 29, 2016

4(c)	Twelfth Supplemental Indenture, dated as of January 18, 2018 between SWEPCo and The Bank of New York Mellon Trust Company, N.A., as Trustee, establishing terms of the 3.85% Senior Notes, Series L, due 2048.	Form 8-K, Ex 4(a) dated January 22, 2018

*12	Statement re: Computation of Ratios.

*13	Copy of those portions of the SWEPCo 2017 Annual Report (for the fiscal year ended December 31, 2017) which are incorporated by reference in this filing.

*23 (1)	Consent of PricewaterhouseCoopers LLP.

*23 (2)	Consent of Deloitte & Touche LLP.

*24	Power of Attorney.

*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

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Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:

*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

*95	Mine Safety Disclosure.

101.INS	XBRL Instance Document.

101.SCH	XBRL Taxonomy Extension Schema.

101.CAL	XBRL Taxonomy Extension Calculation Linkbase.

101.DEF	XBRL Taxonomy Extension Definition Linkbase.

101.LAB	XBRL Taxonomy Extension Label Linkbase.

101.PRE	XBRL Taxonomy Extension Presentation Linkbase.

‡ Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants. The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request.

The agreements and other documents filed as exhibits to this report are not intended to provide factual information or other disclosure other than with respect to the terms of the agreements or other documents themselves, and you should not rely on them for that purpose. In particular, any representations and warranties made by us in these agreements or other documents were made solely within the specific context of the relevant agreement or document and may not describe the actual state of affairs as of the date they were made or at any other time.

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